WO1995026455A1

WO1995026455A1 - Downhole fluid control processes

Info

Publication number: WO1995026455A1
Application number: PCT/GB1995/000722
Authority: WO
Inventors: Harry Frampton
Original assignee: Allied Colloids Limited
Priority date: 1994-03-28
Filing date: 1995-03-28
Publication date: 1995-10-05
Also published as: GB9406125D0; AU2079195A

Abstract

The invention provides an improved method of controlling permeability in downhole formations. The invention provides a downhole process which comprises forcing an aqueous solution of polymer down a well into an insolubilising zone which is in a subterranean formation and which has a higher temperature than the temperature of the solution in the well and insolubilising the polymer in the insolubilising zone. The polymer solution is an aqueous solution of an LCST polymer having an LCST temperature between the temperature of the solution and the temperature of the zone. As the temperature of the solution increases towards the temperature in the zone the polymer becomes insolubilised.

Description

Downhole Fluid Control Processes

This invention relates to downhole processes which involve control of the flow of fluid through a subterranean formation, generally during the recovery of oil from a reservoir in that formation or in a formation that inter-connects with it.

Before or after the recovery of oil due to natural pressures (primary recovery) in the reservoir has been exhausted, it is conventional to apply secondary or tertiary oil recovery methods. In such methods, a fluid flood is forced down an injection well that leads into the reservoir and through the reservoir towards a production well. Generally there are a series of injection wells and a series of production wells in each reservoir. The fluid may be gaseous. For instance, steam injection can be used to recover viscous oils. The fluid may be water or a water-thin liquid in which case the process is usually called a water flood. It may be a more viscous liquid, achieved by the incorporation of water soluble polymer in the flood water, in which event the process is known as a polymer flood.

A common problem with fluid floods is that the reservoir formation is frequently of irregular permeability. The fluid flood will tend to pass preferentially through relatively high permeability regions ("streaks") in preference to flooding uniformly through the reservoir. Since the flood does not then pass uniformly through the reservoir, oil recovery from the lower permeability regions is delayed or reduced. Additionally, the fluid flood that diverts preferentially through the streaks will cause an undesirable increase in the amount of fluid that dilutes the oil collected in the production well. This water or other fluid inhibits oil recovery or has to be pumped to the surface, thereby wasting some of the capacity of the pumping equipment, and then has to be separated from the oil at the surface. It is therefore well known to be desirable to modify the flow of fluid through the formation by blocking the high permeability regions (streaks) in order to force the flood into areas of lower permeability. In one such system, described in, for instance U.S. 3,707,191, a gel-forming solution is used to flood the target zone (i.e. the high permeability zone or streak) and this solution slowly sets to a medium or strong gel, thus blocking the streak. Problems with methods of this sort include the fact that very large volumes of gel-forming solution may be needed unless the target zone is extremely small, and the zone to be treated must be characterised very carefully in order to ensure that the treatment is effective.

An alternative process is the "alternating slug" treatment. This process, described in, for instance, U.S. 4,009,755, involves the injection of a polymer solution into the target zone followed by the injection of a solution containing a cross-linking system. When the polymer and the cross-linking system come into contact a chemical cross-linking reaction takes place, resulting in the formation of a plug of a highly cross-linked gel. Problems with this treatment include the fact that the cross-linker solution may in fact divert around or away from the previously injected polymer solution, which may lead to inadequate mixing and gelation.

Deep diverting gel (DDG) systems are also known which involve the injection of a solution of polymer and further reagents into the target zone. The polymer and reagents are chosen so that they do not react chemically, or react very slowly, at the temperature of injection but react fast when at the natural temperature of the reservoir to produce cross-linked polymer gel aggregates which block rock pores. Systems of this type are described in U.S. 4,903,768 and U.S. 4,974,677. Such systems, like the first-described gel systems, require careful characterisation of the target zone. Systems are also known, for instance as described in U.S. 4,637,467, in which a solution of a monomer mixture and a polymerisation initiator are injected into the target zone where in situ polymerisation takes place to form a plug of insoluble polymer. Monomers described in U.S. 4,637,467 include diacetone acrylamide and acrylamide. This system has the disadvantages that polymerisation takes place in the subterranean formation and mixing, polymerisation rate, monomer ratios and other polymerisation parameters are therefore not easily controlled. Furthermore, the system requires injection of monomers, such as acrylamide, and it is often considered environmentally undesirable to apply the free monomer in the ground.

All the above systems have the disadvantage that the blockage that is formed is permanent in the sense that it will tend to remain in position unless some deliberate chemical removal step is applied, such as the application of a chemical degradation agent. This is inconvenient.

Another problem is that it is difficult, and often prohibitively expensive, to block the entire region of high permeability in an unconfined streak. Instead there will be a tendency to block it in the accessible regions close to the wells. The blockage of the streak will cause the fluid flood to divert away from the blockage into the reservoir, but it may then flow back into the streak beyond the blockage, and if it does this there will be minimal improvement in oil recovery.

Even when these methods are conducted with considerable pre-planning and care, it is still difficult to achieve reasonably uniform permeability through the reservoir and optimum recovery of oil from the reservoir.

These problems are particularly serious with water floods, but they also occur to some extent in polymer floods.

The polymer used in a polymer flood must remain in solution throughout use and the polymer should be such that, despite the hostile conditions downhole, the solution maintains a viscosity during use which is as high as is possible. Insolubilisation of the polymer must be avoided partly because it would lead to undesirable blockage of the reservoir and partly because it would reduce the concentration of polymer in solution, and therefore it would reduce viscosity.

Although various natural polymers and conventional, relatively cheap, synthetic polymers such as copolymers of acrylamide and sodium acrylate are used, there have been various proposals to use special polymers for various reasons. For instance, in order to provide increased tolerance to electrolyte in the flood (and therefore to maintain viscosity despite the presence of electrolyte in the polymer flood) it has been proposed in U.S. 4,430,481, to include polymers in the polymer flood which are copolymers or homopolymers including monomer units based on diacetone acrylamide, N-alkyl acrylamides and N-hydroxyalkyl acrylamides. It would be desirable to be able to improve the flow control of polymer floods through formations of highly variable permeability.

A method of profile control in oil reservoirs is proposed in GB-A-2262117. A dispersion of insoluble, cross-linked polymer latex particles is injected into a region of high permeability. The publication describes flocculation, shrinkage and hardening of the particles at the raised temperatures in the oil reservoir in the presence of an ionic solution. This effect is said to effectively block the region of high permeability. The flocculation is preferably reversible.

It is essential in this method that the polymer is introduced in insoluble particulate form. Insolubility is generally achieved by cross-linking the polymer. Preferred latices are formed from poly N-isopropyl acrylamide homopolymer particles.

One disadvantage of this method lies in the difficulty of forming, in a commercially viable process, cross-linked poly N-isopropyl acrylamide. This cross-linked polymer becomes less water-compatible on heating. The formation of cross-linked polymer is exothermic and tends to lead to premature precipitation and even agglomeration of the particles in the reaction mixture.

A further disadvantage lies in the necessity to inject polymer in particulate form. Injection of polymer particles can result in imperfect penetration of the microporous structure, as well as in retention of the polymer particles in the formation. Both of these effects give rise to uneven distribution of polymer in the formation, and therefore inefficient permeability reduction.

Another downhole, fluid control, process is a shut-off process. Thus it sometimes happens that it is desirable to shut-off, or substantially reduce, the flow of fluid between a production zone and a well, thereby preventing or minimising the production of water or other fluid from the well. Water shut-off can be achieved, for instance, by the injection of a solution of polymer and a cross-linker which is unreactive or slowly reactive at the temperature of injection but which reacts chemically with the polymer at the natural reservoir temperature to form a highly cross-linked gel, in a similar manner as in U.S. 4,903,768. Such systems can be inconvenient when the water is only required to be shut-off temporarily, since the blockage formed in all the shut-off methods known currently is either a permanent one or one which can only be removed with the use of a chemical degradation agent.

It would therefore be desirable to provide a simple method of achieving downhole fluid control, even deep into a formation, by insolubilisation of a polymer, for instance to achieve shut-off or to promote uniformity of fluid flood. It would also be desirable to achieve this under conditions whereby the polymer can easily be solubilised so as to permit increased flow when this is desired. A downhole process according to the invention comprises forcing an aqueous solution of polymer down a well into an insolubilising zone which is in a subterranean formation and which has a higher temperature than the temperature of the solution in the well and insolubilising the polymer in the insolubilising zone, wherein the polymer solution is an LCST polymer solution having an LCST temperature in the solution between the temperature of the solution in the well and the temperature of the zone, whereby the polymer is insolubilised in the insolubilising zone in the formation as a result of the increase in the temperature of the solution towards the temperature in that zone.

Thus we use a solution of the polymer and the dissolved polymer undergoes insolubilisation in the desired insolubilising zone as a result of the natural temperature change that occurs when the polymer solution is injected from a well at one temperature into a subterranean formation having a higher temperature. Often it is preferred that the polymer is insolubilised at one elevated temperature and that insolubilised polymer tends to agglomerate into larger agglomerates or floes at a higher temperature. Preferably the insolubilisation is caused substantially only by the physical effect of the change of temperature, and in particular it is preferred that the insolubilisation is not caused by chemical cross linking or other chemical reaction which it is difficult to reverse downhole. Thus the polymer is preferably a substantially linear polymer (in contrast to a cross-linked polymer) throughout the process. Naturally the substantially linear polymer may be branched provided the branching is not so extensive as to form a cross-linked insoluble network. Preferably the polymer is formed from monomers in the absence of added cross linking agent.

An important advantage of the invention is that the insolubilised polymer can become solubilised again merely by cooling it. Thus important processes of the invention are those in which flow control is achieved by insolubilising the polymer and subsequently different flow control is achieved by reducing the temperature in the insolubilising zone (generally by forcing liquid coolant adjacent to that zone) and thereby solubilising the insolubilised polymer. Generally the solubilised polymer is flushed from the first zone, for instance by liquid coolant that passes through the first zone as well as being forced adjacent to that zone. The liquid coolant may, for instance, be a water flood or, in shut-off processes, it may be any suitable aqueous liquid or other fluid that is pumped down the well for achieving the desired cooling effect.

LCST polymers are Low Critical Solution Temperature polymers. An LCST polymer has the property of being less soluble at increased temperatures than at lower temperatures. The polymer has a lower critical solution temperature at which significant insolubilisation occurs. For convenience, the invention is described in terms of the use of a single LCST polymer having a single LCST point. However in some circumstances it is appropriate to use a polymer solution which provides two different LCST points, either as a result of including two LCST polymers having different LCST points or as a result of using a polymer having two different LCST points. It will be appreciated that when the polymer or polymer blend provides more than one LCST point there may be two different zones at which insolubilisation/solubilisation occurs or there may be a wide range of conditions at which these effects occur.

We also find that many LCST polymers exhibit an agglomeration temperature above the LCST temperature. At the LCST temperature the polymer becomes insolubilised (precipitated). If the temperature of the insolubilised polymer is raised further the insolubilised particles can agglomerate to give larger particulate aggregates or floes. The agglomeration temperature is generally 20 to 30°C greater than the LCST temperature. As with the LCST temperature, in some circumstances it is appropriate to use a polymer solution which provides two different agglomeration temperatures. When a polymer blend is used containing polymers having two different agglomeration temperatures this may result in two different zones of temperature at which agglomeration occurs. Alternatively the polymer blend in solution may exhibit an agglomeration temperature which is different from both the agglomeration temperatures of the individual polymers.

LCST polymers and their solution properties are well known and are described in, for instance, Priest et al, Chapter 18 in "Reversible polymeric gels and related systems", American Chemical Society, 1987, and in U.S.3, 244, 640, 3,567,650 and 3,594,326, WO92/20771 and JP-B-92034983 and JP-B-92034985, JP-A-04139206 and in Galaev and Mattiasson, Enzyme Microb. Technol., 1993, 15, 354-366. Suitable monomers and polymerisation techniques are described in U.S. 5,147,923.

The downhole process of the invention may be a shut-off process wherein the insolubilising zone is the production zone adjacent to the production well, for instance the LCST polymer shuts off a water-producing zone in an oil reservoir. The temperature of the insolubilising zone, where the shut-off is to occur, will generally be the normal reservoir temperature and the LCST polymer is chosen such that it has an LCST which is lower than the reservoir temperature. Preferably also it has an agglomeration temperature which is lower than the reservoir temperature. An aqueous solution of the LCST polymer is forced down the well and into the insolubilising zone, where it becomes insolubilised and preferably agglomerated due to the temperature of the solution rising to the reservoir temperature. It is usually necessary to inject coolant water down the well immediately prior to the injection of the LCST polymer solution so as to cool the well, and if necessary the surrounding region, sufficient to prevent insolubilisation and agglomeration of the LCST polymer until it reaches the desired insolubilising zone.

The insolubilised, often also agglomerated, polymer forms a plug which blocks the zone where it is formed and thus provides effective shut-off.

The shut-off is selectively reversible upon adequate cooling of the zone containing the insolubilised and often agglomerated plug of polymer. This cooling can be achieved by forcing coolant water or other liquid adjacent to the insolubilised zone sufficient to cool the zone and permit adequate de-agglomeration and solubilisation of the LCST polymer. The coolant may merely be pumped down the well or it may be forced into the formation and around and adjacent the plug sufficient to cool that.

The invention is, however, primarily of value in oil recovery processes wherein oil is displaced from a reservoir in the subterranean formation by forcing the fluid flood through the formation and the insolubilising zone is a relatively high permeability region (i.e., streak) in the formation. In the invention this streak or relatively high permeability region is the insolubilising zone and the polymer is insolubilised in this streak as a result of the increase in the temperature of the polymer from the injection temperature towards the temperature in the reservoir, whereby the insolubilised polymer preferentially reduces the permeability in the streak. If the temperature of the insolubilised polymer then increases towards the agglomeration temperature of the polymer the insolubilised polymer then becomes agglomerated and further reduces permeability in the streak. When carrying out this process, conditions (such as the concentration and amount of polymer) may be selected such that the insolubilisation and any agglomeration of the polymer in the streak merely reduces the permeability within the streak such that it is, for instance, then approximately the same as the permeability of the less permeable parts of the formation.

However the reduction can alternatively have the effect of blocking the streak so as substantially to prevent any movement of flood through the blockage.

The usual way of performing the fluid flood aspect of the invention is as follows. The fluid flood is initially forced down the well and injected into the reservoir in conventional manner. The fluid flood has a temperature in the well (i.e., at the point where it is about to emerge from the well into the subterranean formation) which is below the natural temperature of the formation and the reservoir. The fluid flood therefore cools those parts of the formation that it contacts while it still has a temperature below the reservoir temperature. As a result, there is a temperature profile through the reservoir consistent with the presence of a streak in that it shows the gradation in temperature from the flood temperature in the well to the natural reservoir temperature. If the formation had uniform permeability the temperature gradient would be relatively uniform throughout the formation. However where the formation has relatively high permeability zones, the fluid flood will travel at a greater rate than elsewhere and so regions of relatively high permeability will be cooler. As a result, a temperature profile close to the injection well will show a rapid-rise from the flood temperature to the reservoir temperature in most parts of the formation except in regions of increased permeability (streaks) where the profile will extend more deeply into the formation.

When it is considered necessary to block or reduce the flow through the streak, sufficient of the solution of LCST polymer is forced down the well (usually after stopping the flood) at a temperature such that the polymer is in solution when it is injected from the well into the formation. The injected LCST polymer solution "slug" predominantly enters the high permeability zone or zones. The solution will flow through this zone or zones and will be exposed to a temperature gradient that extends both parallel to the injection well and perpendicular to the injection well. The gradient may be relatively shallow in either or both of these directions. By appropriate choice of the amount and type of polymer, and in particular by selection of a polymer or polymer blend having appropriate LCST characteristics, it is possible for the polymer to be insolubilised, and often agglomerated, through a substantial volume of the high permeability zone or zones. Once it is judged that the desired reduction in permeability through the previously high permeability zone or zones has been, or will be, achieved, fluid flood may then be resumed.

The introduction of the LCST polymer solution "slug" may result in a lesser amount of the polymer entering the low permeability zone or zones. The amount that enters will often be adsorbed onto the reservoir rock such that it does not create any significant blockage and the LCST polymer may, in any event, easily be washed into the streak by post-flush water. In particular, any polymer in the relatively low permeability zones will have been deposited near to the well and so will tend to be resolubilised quickly when the flood is resumed. However the fluid flood will have limited or no access to the polymer deposited throughout the depth of the streak and so will, instead, divert around the blocked streak.

By appropriate control of the nature and amount of polymer solution it may be possible to insolubilise and, preferably, agglomerate polymer throughout substantially the entire volume of the streak, but if there is a high permeability zone on the side of the streak distant from the injection well there may be a tendency for the fluid flood to divert around the blockage and into this high permeability zone. If it does, the whole process can be repeated again so as to achieve permeability reduction in a zone beyond the initial zone in which polymer is insolubilised. Thus the process of performing fluid flood, injecting LCST polymer solution and then resuming fluid flood may be repeated to achieve permeability reduction in the same or different zones.

As a result of forcing relatively cool fluid flood adjacent to and around the zone where polymer has been insolubilised, the zone will be subjected to external cooling, thereby reducing its temperature, initially from the outermost portions of the zone. It is therefore possible to solubilise some or all of the insolubilised polymer and to flush it from that zone by the fluid flood. If, as may frequently occur, this cool solution of LCST polymer migrates preferentially through a continuation of the streak, it will again be heated to above the LCST and will again become insolubilised and often agglomerated within the streak.

Thus the invention provides a process in which the insolubilising zone in which insolubilised polymer is deposited can move during the process in response to the temperature profile at any particular time in the formation. By appropriate selection of the LCST polymer, its concentration and its amount, having regard to the temperature of the fluid flood and the natural temperature of the formation, it is possible to significantly reduce unacceptable variations in permeability in the formation by a technique which allows polymer blockages in the formation to be redissolved with relative ease, when this is required.

As indicated above, the problem of variable permeability is often acute when the fluid flood is a water flood (either using water or a water-thin fluid) and the invention is preferably applied to water floods. The water flood is conducted using locally available water.

The water flood may comprise dissolved components such as inorganic salts. Sea water is often used as a water flood and usually contains at least 3% (30,000 ppm) inorganic salts, particularly sodium chloride. It may also contain calcium and magnesium salts, for instance chlorides, sulphates and hydrogencarbonates. However the invention can also be applied to polymer floods that are conducted using, as the viscosifying polymer, a polymer that is not insolubilised by temperature changes during the process. Thus the polymer of the polymer flood may be a conventional synthetic or natural viscosifying polymer that remains in solution throughout the process. If it is desired that the polymer should have good resistance to electrolyte then this is best achieved by, for instance, copolymerising with a monomer such as 2-acrylamido methyl propane sulphonic acid (AMPS, U.S. trade mark) rather than by incorporating monomers that could under some conditions cause the polymer to insolubilise on heating. As mentioned above, it is proposed in U.S. 4,430,481 to conduct a polymer flood with a copolymer of acrylamide and diacetone acrylamide and such a polymer may be an LCST polymer. However since precipitation of the polymer would have been disastrous to the polymer flood, in prior processes it will have been used only in reservoirs where the natural temperature is sufficiently low that there is no insolubilisation of the polymer in the reservoir.

Gaseous floods may also be used, for instance steam, carbon dioxide, nitrogen or hydrocarbon gas.

A blend of LCST polymers may be used, for instance having different LCST and agglomeration points. The or each LCST polymer may be a naturally occurring polymer such as certain cellulose derivatives, such as the methyl, hydroxypropyl and mixed methyl/hydroxypropyl cellulose ethers. However it is generally preferred for the LCST polymer to be a synthetic polymer formed by polymerisation of what can be termed an LCST monomer (or more than one such monomer), optionally as a copolymer with one or more further types of monomer. Suitable LCST monomers include N-alkylacrylamide, N,N-dialkylacrylamide, diacetone acrylamide, N-acryloylpyrrolidine, vinylacetate, certain (meth) acrylate esters (especially hydroxypropyl esters), styrene, and various other vinyl monomers, especially N-vinylimidazoline and the like.

When the LCST polymer is a copolymer with other monomers, the co-monomer is usually hydrophilic and can be non-ionic or ionic. Suitable non-ionic monomers include acrylamide (ACM), substituted acrylamides for instance those with one or two aliphatic N-substituents, some of which, such as N,N-dimethyl acrylamide (NNDMACM), may contribute to LCST properties, hydroxyethyl acrylate, vinylpyrrolidine and hydrolysed vinyl acetate.

Anionic or cationic monomer can be used in place of or in addition to the non-ionic co-monomer to form a copolymer or terpolymer respectively with the one or more LCST monomers. Suitable anionic monomers include ethylenically unsaturated carboxylic or sulphonic acid monomers, for example (meth) acrylic acid and alkaline salts thereof, and 2-acrylamido methyl propane sulphonic acid. Suitable cationic monomers include dialkyl amino alkyl (meth) acrylates and acrylamides as acid addition products of quaternary ammonium salts, for example dialkylaminoethyl (meth) acrylate acid addition salts.

Diacetone acrylamide (DAAM), N,N-dimethyl acrylamide (NNDMACM), N-isopropyl acrylamide (NIPA) and N-hydroxypropyl acrylamide are particularly useful LCST monomers. LCST polymers which may be used include DAAM/ACM copolymers, NNDMACM/NIPA copolymers, NNDMACM/ACM copolymers, NIPA/ACM copolymers and poly-N-isopropylacrylamide (poly-NIPA) homopolymer.

Certain monomers exhibit particularly high thermal stability under conditions simulating those in a treatment formation. These include N,N-dimethyl acrylamide and N-isopropyl acrylamide. Thus when the conditions of use of the polymer solution require the polymer to exhibit particularly good thermal stability it is preferred to choose these highly thermally stable monomers.

The amount of LCST monomer is usually at least 50% and frequently at least 70% by weight of the polymer. It can be 100% but is generally not more than 95%, and often is not more than 85% by weight of the polymer.

Preferred polymers are formed from 50 to 100% LCST monomer, copolymerised if desired with other suitable monomers. Non-ionic comonomers are preferred, such as acrylamide. It is often preferred to use polymers formed of 100% LCST monomer, either as homopolymers, for instance poly NIPA or copolymers of two or more different LCST monomers. For instance NNDMACM/NIPA or NNDMACM/DAAM copolymers are particularly preferred for their high thermal stability.

It is essential that the polymer is injected into the formation in aqueous solution, that is it must be essentially completely soluble in the aqueous injection solvent, which is usually sea water. This ensures that the solution can be injected fully into the microporous structure of the zone for which it is intended.

The polymers in the solution are therefore most often substantially linear, although a small amount of branching or cross-linking may be present as long as it does not result in the polymer being insoluble in the treatment solution.

Injection of polymer in aqueous solution form contributes to reduction in both adsorption of polymer into the formation and in filtration out of polymer by trapping at an early stage. We find that adsorption is considerably reduced with respect to polymers used in polymer floods. Absolute values of amount of polymer adsorbed vary according to the nature of the particular rock from which the reservoir is formed. In static bottle tests using polymer at concentrations up to 5,000ppm dissolved in API sea water also containing 15wt% crushed Clashach core at polymer, the polymer solutions used in the process of the invention give adsorption values preferably below 3mg of polymer per gram of rock, more preferably below 2mg polymer per gram of rock, most preferably below 1 or 0.5mg of polymer per gram of rock. Absorption values of below 0.25mg polymer per gram of rock can also be achieved.

The polymers may be formed in any conventional manner for the production of soluble polymer, in particular LCST polymer. For instance they may be made by bead or bulk solution polymerisation.

The lower critical solution temperature of the polymer, i.e. the temperature at which it begins to insolubilise out of solution, may be tailored by those skilled in the art to the value required. The agglomeration temperature may also be tailored. This tailoring of LCST and agglomeration temperatures may be done by, for instance, choosing appropriate monomers or co-monomers; choosing particular proportions of co-monomers; including other components in the polymer solution which have the effect of changing the temperature at which the polymer precipitates in the solution.

In preferred compositions we include an LCST-modifying additive with the polymer in the aqueous solution. Such additives include water-miscible liquids, urea and inorganic salts. Choice of suitable water-miscible liquids allows the LCST temperature to be raised or lowered as desired. Generally the aqueous solvent is injection brine or seawater. Water-miscible solvents which may be mixed with the aqueous solvent include alcohols, in particular those having from 3 to 8 carbon atoms, glycols such as butyldigol, polyethylene glycols, alkoxy alcohols (for instance 2-butoxyethanol) and ketones (for instance acetone).

We also find that these additives have a similar effect on agglomeration temperature.

It has been found that polyethylene glycols and acetone tend to increase the LCST and agglomeration temperature of a polymer, whereas 2-butoxyethanol has a tendency to reduce the LCST temperature. Under some circumstances it is advisable not to use acetone because of its flammability. In general the effect of including a water-miscible liquid increases with the proportion of the liquid added. Amounts of water-miscible liquid added may vary according to the LCST temperature required, in particular from about 1% to about 15%, often up to about 25%, for instance 2 to 12%, often 2 to 5 %. Preferably the amount is not more than about 10%.

A further component which may be included in the LCST polymer solution is urea. This has a tendency to raise the LCST temperature and agglomeration temperature.

We find that the LCST of the polymer in the solution is increased as the concentration of polymer decreases. Decreasing polymer concentration has a similar effect on the agglomeration temperature.

Generally the polymer solution is made up in seawater, brine or saline produced water, due to its great abundance near many oil fields. We find that the LCST and agglomeration temperature increase as the brine strength (concentration of salts in the seawater) decreases. In particular both LCST and agglomeration temperature of most polymers are higher in pure water than in brine.

The particular value of the lower critical solution temperature which is found to be most suitable will depend upon the conditions in the oil reservoir, in particular the natural reservoir temperature. Preferably the natural reservoir temperature is at least 10°C above the LCST of the polymer, more preferably at least 20°C or even 30°C or 40°C above the LCST.

Preferably the temperature of the injected fluid flood is at least 10°C below the LCST of the polymer, more preferably at least 20°C below the LCST.

It is sometimes preferred that the or each LCST polymer should be insolubilised (and optionally resolubilised) over a relatively narrow temperature range which typically is not more than 30°C and is preferably below 10°C, most preferably below 5°C. This temperature range typically is less than 50%, generally less than 30% and preferably less than 10% of the difference between the temperature of the fluid flood when it is injected from the well and the LCST of the polymer. However in some processes it is desirable for the polymer to be insolubilised over a wider range of temperatures.

Oil reservoirs in which water and polymer flooding is used tend to have natural temperatures of between 15°C and 150°C, in particular 42°C to 100°C, most often 50°C to 90°C. LCST may be chosen within these ranges. In this specification LCST is measured visually, by observing the aqueous polymer solution to be used in the process in an 8oz jar as it is heated slowly from room temperature. The LCST is the point at which a black cross drawn on one side of the jar is no longer visible from the other side, through the solution. The LCST of the polymer is suitably between 30°C and 90°C, often between 40 and 80°C. The LCST of the polymer should be chosen so that the injected polymer solution reaches the LCST of the polymer suitably quickly on contact with the thermal front. It should also be chosen so that the insolubilised polymer is cooled to its LCST by the flooding fluid suitably quickly so that it may begin to propagate through the streak with the fluid flood. Naturally the polymer should be selected such that it has adequate chemical stability under the conditions prevailing in the formation in which it is to be used.

It is preferred that the natural reservoir temperature is above the agglomeration temperature of the polymer. Insolubilisation without agglomeration can effectively block micropores and some macropores of the formation and can give adequate treatment results alone, in particular where permeability is required to be reduced only to be the same as that of lower permeability regions. Where a greater lowering of permeability is required it is preferred that the polymer agglomerates after becoming insolubilised. This can increase the effectiveness of blockage of micropores and, especially, macropores and larger cracks and flaws in the formation. Generally agglomeration temperature is 20 to 30°C higher than LCST temperature. In this specification agglomeration temperature is measured visually, by observing the solution to be used in an 8oz jar as it is heated slowly from room temperature. The agglomeration temperature is judged as the point where flocculation of the precipitated polymer is observed. Where agglomeration is desired to occur the reservoir temperature is preferably at least 10°C above the agglomeration temperature, more preferably at least 20°C above the agglomeration temperature, although effective results can be achieved with an agglomeration temperature which is around 5°C below the natural reservoir temperature.

It may be preferred that the polymer agglomerates over a narrow temperature range, for instance not more than 30°C, preferably not more than 10°C. In some processes it is desirable for the polymer to become agglomerated over a wider range of temperatures.

In some circumstances it may be appropriate to use a polymer solution which comprises more than one LCST polymer. The different polymers may have different lower critical solution temperatures and agglomeration temperatures.

The intrinsic viscosity of a suitable LCST polymer will generally be at least 0.1 dl/g and usually between 0.5 and 2.5 dl/g. Preferably it is not more than 5 dl/g. Intrinsic viscosity is measured by a suspended level viscometer at 25°C in buffered 1M NaCl.

The concentration of the LCST polymer in the injected solution may vary and is usually between 0.1 and 10%, preferably between 0.5 and 5%, often about 2%.

LCST monomers have been known as components of solutions used in polymer flooding, because of their increased viscosification at high electrolyte concentration. For instance copolymers of acrylamide and diacetone acrylamide have been proposed for this application, as stated in U.S. 4,430,481. However, precipitation of polymer in polymer flooding is considered a serious disadvantage and polymer floods are tailored as far as possible to avoid this. In fact, polymer floods comprising LCST-type polymers such as DAAM/ACM would generally not be used in reservoirs whose natural temperatures are high enough to lead to significant precipitation of the polymer. One novel aspect of the present invention is that an effect that was previously thought to be a disadvantage has been used in a different application to achieve a desirable effect.

As mentioned above, the LCST and agglomeration temperature of a polymer may be controlled by the selection of appropriate co-monomers and appropriate co-components of the composition and molecular weight of the polymer. It is therefore possible to select a composition and molecular weight of the LCST polymer itself which will lead to precipitation and often agglomeration of the polymer across a given temperature range and re-solubilisation in the presence of any given flooding water, brine or polymer solution.

Example 1

The polymer used in this example (polymer 1) is a low molecular weight copolymer of diacetone acrylamide (60wt%) with acrylamide (40wt%) which was found to have an LCST in sea water of 43°C at 1% polymer concentration. This was done by placing samples of solution in 4oz bottles and heating them slowly from room temperature. A cross was drawn on each bottle of solution, visible through the solution. The LCST point was the point at which the black cross was no longer visible through the solution. When tested in synthetic sea water polymer 1 was completely soluble below 40°C, formed an obviously turbid solution at 45°C and started to precipitate in bulk at 55°C.

A 1% solution of polymer 1 in API sea water was used. API sea water alone was used as a model water flood. The dissolved components of API synthetic sea water are given in Table 1 below.

A 400mD Berea core slice (11mm long, 15mm diameter) to simulate part of an oil-bearing formation was mounted in Araldite epoxy resin and incorporated into a filterability rig which could inject solutions at a pre-set temperature, through the core using 20psi nitrogen over-pressure with the flow rates being monitored.

API sea water was initially injected through the core at 45°C to stabilise the core until a steady flow rate was achieved. This was followed by injecting a 1% solution of polymer 1 in API sea water at 45°C with the effluent being retained. A post flush with cold API sea water followed the 45°C test until the flow rate was linear.

Using the effluent from the previous flood, injectivity tests were carried out in sequence at 50, 55 and 60°C.

The results may be summarised as in Table 2 below. The overall results show the ability of polymer 1 to reduce the permeability of a core.

Resistance factor (RF) is the well known measure of the relative ease of moving a treatment solution through a core compared with moving water through the same core. Residual resistance factor (RRF) is the measure of the relative difficult of moving water through a core after treatment with polymer compared with moving water through the core before treatment. High values of RF and RRF signify high increased resistance. In Table 2, final column, the value given is RF where the flush is with polymer solution and RRF where the flush is API sea water.

In this example the first flush with API sea water at 45°C was carried out to begin stabilisation of the core. The flow rate was very high on initial injection, fell during injection and stabilised at the value given in the table. This is a known effect, characteristic of laboratory tests in which a high initial flow rate is used. It is believed to be caused by mobilisation of clay or fine sand particles within the core. These can migrate into pore throats and reduce the overall permeability.

The second flush with 1% Polymer 1 at 45°C showed a similar trend, in that the flow rate steadily decreased from the initial flow rate and stabilised at a lower rate than in the previous test.

The third flush with cold (20°C) API sea water was carried out to illustrate re-dissolution of precipitated polymer on cooling. This was indeed shown, with the flow rate stabilising at a higher level than shown after the previous polymer flush. This level was also higher than with the first flush with sea water only. This is a known effect and is thought to be brought about by interaction of polymer with fines and stabilisation of these. Subsequent results were compared with the second API sea water flush, since this represented the more uniform state of the core. Thus the 20cm /minute flow rate was used to establish the value of the RF or RRF in all subsequent tests.

The subsequent experiments are designed to simulate what would happen as a "slug" of polymer solution propagates along a zone of high permeability. At the entrance to this zone (the streak) the temperature is below the LCST of the polymer and no insolubilisation occurs. As the polymer solution moves further into the streak it is heated and eventually the polymer insolubilises. As the solution propagates, insolubilised polymer remains in the pores and is thus "filtered out" of the solution, whose concentration is progressively diminished. To simulate this effect effluent polymer solution from the 45°C flood was injected into the same core at 50°C. The system did not reach equilibrium during this flush but it was observed that the flow rate progressively reduced. Consequently the RF was progressively increasing. The experiment was terminated with RF below 5 but increasing. This shows progressive insolubilisation of polymer and blocking of the core.

A second flush of cold APIC sea water was then passed through the core. The subsequent increase in final flow rate and the decrease in the RRF value demonstrates the redissolution.

Effluent from the 50°C flood was injected back into the core at 55°C. The residual resistance factor generated by this flush was 2.7. This is an adequate value but higher values are preferred and achievable in the invention, as illustrated by the next flush at 60°C. Effluent from the 55°C flush was reinjected at 60°C without an intervening flush with API sea water, thus simulating a resistance factor increase caused by insolubilisation of polymer as a result of a 10°C rise in temperature. This gave a much higher resistance factor.

These results indicate that polymer solution propagating through a streak will begin to insolubilise and reduce permeability when its LCST is reached and continue having an effect as polymer is removed from solution at the leading edge of the slug. Greatest effects are seen where the temperature gradient is steepest. Effects may also become greater as the polymer reaches its agglomeration temperature.

RF/RRF values calculated in Table 2 were with 20cm /minute as the reference.

Example 2

This example illustrates the effect on LCST temperature of inclusion in the polymer solution of various components.

2% aqueous solutions of polymer 2 (57wt% diacetone acrylamide, 43 wt% acrylamide, I.V. about 1.4) was made up in synthetic UK North Sea Water and in API seawater as used in Example 1. The synthetic North Sea Water has the following composition

In each solution were included various additional components in amounts of 5, 10 and 15% by weight. The solutions were mixed thoroughly, placed in 8oz bottles in a water bath and heated slowly. The LCST temperature was noted. In all of these examples LCST temperature was noted by drawing a black cross on each bottle of solution, visible through the solution. The LCST point was the point at which the black cross was no longer visible through the solution. Results are shown in Tables 3 and 4 below. The LCST temperature of polymer 2 in API seawater only was measured as 40°C and in Synthetic North Sea Water only it was measured as 44°C.

These results show that polyethylene glycols and acetone in particular have a tendency to increase LCST. Butyldigol has this tendency to a lesser degree, as does propan-2-ol. Octan-1-ol has a tendency to decrease LCST temperature of polymer 2 in both environments. 2- butoxyethanol shows this tendency in Synthetic North Sea Water and in API sea water when used in the larger amounts. Example 3

This example is a further illustration of the effects of inclusion in the polymer solution of various solvents.

Tests were carried out as described in example 2 using 2% aqueous solutions of a new batch of polymer 2 containing various water-miscible solvents in amounts of 5 and 10%. The water bath was set at around 90°C. LCST temperature was noted. Agglomeration temperature was also noted. This was judged visually as the temperature at which flocculation of the insolubilised precipitated polymer occurred. Results are as shown in tables 5 and 6 below.

These results confirm that PEG 200 and PEG 400 increase the LCST, as does butyldigol to a lesser extent. All three have a similar effect on the agglomeration temperature. 2-butoxyethanol decreased both the LCST and agglomeration temperature in the samples tested. Generally a larger effect was seen with a greater amount of solvent.

Example 4

This example shows the effects of addition of urea to a solution of a further batch of polymer 2. Six 2% solutions of polymer 2 were made up in API sea water. Urea was added at levels of 0.5%, 1%, 2%, 3% and 5% by weight. The solutions were tumbled for 15 minutes. The six solutions were then placed in a water bath and heated slowly. The LCST temperature was noted for each solution. Results are shown in Table 7 below.

This illustrates the effect urea has to increase LCST temperature of polymer 2.

Example 5

In this example, solutions of a further batch of polymer 1 were made up at 0.5%, 1.0% and 2.0% active in three synthetic brines:-

1. Synthetic North Sea Water as used in Example 2.

2. Synthetic North Sea Water diluted to 32,762ppm TDS with deionised water, content as follows:

3. Synthetic North Sea Water diluted to half strength (17,917ppm TDS) with deionised water, content as follows:

After being tumbled for 2 hours the solutions were placed in a water bath set at approximately 85°C and the LCST was measured as the temperature at which a black cross on the far side of the bottle disappeared.

Heating was continued, after measurement of the LCST, until a temperature was reached at which large floes appeared. This temperature was recorded as the Agglomeration Temperature. Results are shown in Table 8 below.

All results are in °C.

These results show the general trend to increase in both LCST and agglomeration temperature with decreasing polymer concentration and with decreasing brine strength. Example 6

This accelerated laboratory simulation gives an illustration of comparative thermal stability of various LCST polymers.

1% solutions of the samples were made up in Synthetic North Sea Water as used in Example 2, heated to above their agglomeration temperature and placed in an oven at 95°C.

The solutions were removed and observed periodically to check whether the floes or precipitate were still present.

Polymers were as follows:-

Polymer 3: 50wt% NNDMACM, 50wt% DAACM

Polymer 4: 50wt% NNDMACM, 50wt% NIPA

Polymer 5: 35wt% ACM, 65wt% DAACM

Polymer 6: 35wt% ACM, 65wt% NIPA

Results are shown in Table 9 below.

The copolymers containing acrylamide remained agglomerated for around 11 days. Polymer 5 appeared to de-agglomerate and re-agglomerate at about 43 days. Polymer 6 de-agglomerated but precipitate remained for at least 112 days. Copolymer containing NNDMACM showed exceptional stability and remained agglomerated after 126 days at 95°C. Example 7

In this example the reduced absorption of the polymers used in the process of the invention is demonstrated in comparison with two commercial polymers used for mobility control.

The polymers used were Alcoflood 1175A, Alcoflood 935 (both available from Allied Colloids Limited) and Polymer 1.

Samples of the commercial polymers were made up at 0.2wt%, the usual usage concentration for these. Solutions of Polymer 1 were made up at 0.03wt%, 0.1wt% and 0.5wt% in API sea water. Each solution was mixed with an equal volume of a 30wt% slurry of crushed and ground Clashhach core rock in API sea water. The mixtures were left to stand overnight at 45°C.

Amounts of polymer absorbed onto the rock were measured. For Alcoflood 1175A, 3.9mg polymer per gram of rock were absorbed. For Alcoflood 935, 4.2mg of polymer per gram of rock were absorbed. Polymer 1 gave absorption values of 0.4mg per gram rock, 0.5mg per gram rock and 0.2mg per gram rock at 0.03wt%, 0.1wt% and 0.5wt% respectively.

This illustrates the low absorption of polymers of the type used in the invention in comparison with conventional polymer flood products.

Claims

1. A downhole process which comprises forcing an aqueous solution of polymer down a well into an insolubilising zone which is in a subterranean formation and which has a higher temperature than the temperature of the solution in the well and insolubilising the polymer in the insolubilising zone characterised in that the polymer solution is an aqueous solution of an LCST polymer having an LCST temperature in the solution between the temperature of the solution in the well and the temperature of the zone, whereby the polymer is insolubilised in the insolubilising zone in the formation as a result of the increase in the temperature of the solution towards the temperature in that zone.

2. A process according to claim 1 in which the insolubilised polymer is subsequently solubilised by reducing the temperature in the insolubilising zone.

3. A process according to claim 2 in which the temperature is reduced in the insolubilising zone by forcing liquid coolant adjacent to that zone.

4. A process according to any preceding claim and which is a shut-off process wherein the insolubilising zone is a production zone adjacent to a production well.

5. A process according to claim 4 in which the shut-off is selectively reversible by forcing coolant liquid adjacent to the insolubilised zone sufficient to cool the zone and permit solubilisation of the LCST polymer.

6. A process according to any of claims 1 to 3 which is an oil recovery process wherein oil is displaced from a reservoir in the subterranean formation by forcing fluid flood through the formation and the insolubilising zone is a streak in the formation and the polymer is insolubilised in this streak as a result of the temperature to which the polymer is exposed being raised towards the temperature in the streak and above the LCST of the polymer.

7. A process according to claim 6 in which fluid flood is forced down the well and injected into the reservoir until a temperature profile has been developed in the reservoir consistent with the presence of a streak, and then sufficient of the solution of LCST polymer is forced down the well at a temperature such that the LCST polymer is in solution when it is injected from the well into the formation but is insolubilised in the streak.

8. A process according to claim 7 in which fluid flood in the absence of LCST polymer is subsequently resumed.

9. A process according to claim 7 or claim 8 in which the fluid flood is flooding with water or a water-thin liquid.

10. A process according to claim 7 or claim 8 in which the fluid flood is flooding with steam.

11. A process according to any preceding claim in which the LCST polymer is a copolymer of 50 to 100% LCST monomer with 0 to 50% acrylamide, N,N-dimethylacrylamide, sodium acrylate. Amps, or quaternary dimethylaminoethyl (meth) acrylate, wherein the LCST monomer is selected from N- isopropylacrylamide, diacetone acrylamide and N-hydroxypropyl acrylamide.

12. A process according to any preceding claim in which the LCST polymer is a substantially linear polymer.

13. A process according to any preceding claim in which the insolubilised polymer is agglomerated in the insolubilising zone at a temperature above the LCST temperature.