GB2412390A

GB2412390A - Process for acid fracturing of underground formations

Info

Publication number: GB2412390A
Application number: GB0406995A
Authority: GB
Inventors: Ralph Edmund Harris; Ian Donald Mckay
Original assignee: Cleansorb Ltd
Current assignee: Cleansorb Ltd
Priority date: 2004-03-27
Filing date: 2004-03-27
Publication date: 2005-09-28
Also published as: GB0406995D0

Abstract

A process for increasing the acid fracturing of an underground formation penetrated by a wellbore, which process comprises: <SL> <LI>(a) injecting a fracturing fluid into the formation under sufficient pressure to fracture the formation, wherein the fracturing fluid contains a solid polymer capable of being converted by hydrolysis into one or more organic acids; <LI>(b) allowing the solid polymer to enter the fracture so generated; and <LI>(c) allowing the solid polymer to hydrolyse in the presence of water to produce organic acid within the fracture. </SL> The polymer may be an aliphatic polyester, e.g. a polylactide or polyglycolide.

Description

1 2412390

PROCESS FOR ACID FRACTURING OF UNDERGROUND FORMATIONS

The present invention relates to the acid fracturing of underground formations.

Fracture acidizing, also known as acid fracturing or acid fraccing, is a widely used acidizing technique for stimulating fluid production from limestone or dolomite formations. The technique may also be used to increase injectivity. In an acid fracturing treatment a pad fluid, or sometimes only acid, is injected into the formation at a rate higher than the reservoir matrix will accept. This rapid injection produces a buildup in wellbore pressure until it exceeds the compressive earth stresses and tensile rock strength. At this pressure the formation fails, leading to cracking (fracturing) of the rock. This is also referred to as "breaking down". Continued fluid injection increases the fracture's length and width. A suitable acid (normally hydrochloric acid, such as 15% HCI) is then injected into the fracture to react with the formation and create, by etching of the fracture surface, a flow channel that extends deep into the formation. This allows more reservoir fluid to drain into the wellbore along the etched fracture once the well is put back on production and increases the production rate.

The key to success is penetration of reactive acid along the fracture. The effective length of an acidised fracture is limited by the distance that acid travels along the fracture before it is spent. This is controlled by the acid fluid loss, the reaction rate and the fracture flow rate. One situation in which acid spends rapidly is when the acid reaction rate is high owing to high formation temperature.

The acid fluid-loss mechanism is more complex than that of non-reactive fluids. In addition to diffusive leak off into the formation, flowing acid leaks off dynamically by dissolving the rock and producing worrnholes. Wormholes are very detrimental in fracture acidizing. They greatly increase the effective surface area from which leak off occurs and are believed to affect acid fluid loss adversely. Acid leaks off predominantly from wormhole tips rather than the fracture face. As worml!oling and excessive leak-off occur, the leak-off rate exceeds the pump rate, and a positive net fracturing pressure cannot be maintained to keep the fracture open. At this point in the treatment, which may be as soon as just several minutes (of the order of 5 to 6 minutes) after starting to pump acid, the fracture extension slows or stops.

Acid fluid loss control has long been a problem in fracture acidizing and limits the extent of reactive acid penetration along the fracture. Retarding the rate of the acid reaction could potentially be used to improve the effectiveness of acid fracturing treatments. Acids may be regarded as retarded for acid fracturing purposes only if their reaction rate during flow along the fracture is significantly lower than the reaction rate of hydrochloric acid alone.

Types of retarded acid systems known in the art include viscous acid systems, gelled acid systems, chemically retarded acid systems, and organic acid systems [Reference: Acidizing Fundamentals (1979). Williams B.B. et al, SPE Monograph No. 6 New York and Dallas].

Viscous acids include emulsified acids and acids gelled with guar or other polymers. Typically the acid (28% hydrochloric acid) is mixed with kerosene or other suitable oil to form either an acid external phase emulsion or an acid internal phase emulsion. The retardation provided by emulsified acids is primarily a result of the high emulsion viscosity, which reduces the rate of mass transfer to the fracture wall.

Shielding by the oil layer may also provide a measure of reduction in the reaction rate.

When retarding the rate of reaction of the acid by the use of viscous pads or acid solutions the principle behind these processs is to lay an impermeable filter cake on the fracture face and minimize wormholing. In practice these filter cakes are relatively ineffective in controlling acid fluid loss because of the quick penetration by worrnholes and the constant erosion of fracture faces during treatment.

When viscous acids are used often very large volumes of fluid are needed in order to assure adequate fracture conductivity. Gelled acids are commonly prepared by adding polymers such a guar, gum karaya or polyacrylamide to hydrochloric acid.

The resulting viscous acid is retarded so long as the fluid is viscous. Unfortunately, the viscosity of the gelled acid is quickly lost because the gelling agent typically degrades due to elevated temperature encountered in the well bore and the formation.

The highly temperature dependent nature of gelled acid often makes its use undesirable prom a field operation and cost effectiveness viewpoint.

Chemically retarded acids such as those containing oil wetting surfactants have been reported as being effective in reducing the reactivity of hydrochloric acid in laboratory tests. However, at typical field flow rates, the retarding effect of the oil wetting surfactants is often not realized and the acid reacts as would regular hydrochloric acid. Changes in the Nettability of the formation may also occur during such treatments. These are undesirable and may necessitate a remedial treatment.

Organic acids such as acetic acid and formic acid have been used either alone or in mixtures with hydrochloric acid. These mixtures of acids have been reported as being usefi1 as retarded acid systems. Generally the reaction rate for organic acids is lower than for hydrochloric acid. However, fracture penetration distances achieved using acetic acid or formic acid are similar to those achieved using conventional hydrochloric acid. Fluids used in the fracture acidizing processes (pad fluid, acid or additives) can be detrimental to well performance following the job. This can be due to clean up problems or a reduction in the formation permeability adjacent to the fracture.

Problems are particularly pronounced in the case of gas wells. A particular problem is the removal of high viscosity fluids. The time required to achieve cleanup increases significantly as fluid viscosity increases. For example, in a gas well in a 0.1 rnD permeability formation, a fluid such as oil or water that has a viscosity of 0.25 cP at reservoir temperature is easily removed from the formation. Maximum production rate is attained after about 3 days. At 25 cP viscosity, maximum rate is attained after about 20 days. 250 cP fluid is difficult to remove from the formation and only 24% of the fracture fluid will have been produced after 400 days of production. Similar increases in cleanup time are seen as fracture length increases [Reference: Acidizing Fundamentals (1979). Williams B.B. et al, SPE Monograph No. 6 New York and Dallas].

ideally the best acid system for fracturing is one that only etches the fracture face by dissolution and leaks off into the formation mainly by diffusion [Reference: Mukherjee, H & Cudney, G. Extension of Acid Fracture Penetration by Drastic Fluid Loss Control. Journal of Petroleum Technology February 1993 pp. 102-105].

US 3,968,840 teaches the use of solid acids such as sulfanilic acid introduced into the formation in a fluid which subsequently dissolve in water and differentially etch the fracture faces. However, the acids described in US 3,968,840 in some cases may dissolve faster than desired in water so to obtain useable rates of dissolution and soluble acid delivery they may need to be introduced in a non-aqueous fracturing fluid such as a hydrocarbon. The rate of production of acid then becomes dependent on the rate of Nixing of the sulfanilic acid with formation or introduced water within the fracture and the extent of mixing may be variable along the fracture.

US 6,207,620 teaches the use of a variety of encapsulated acid as a means of acid fracturing of formations. Acid is encapsulated in cross-linked vegetable oils, insoluble polymers such as polyvinylchloride and nylon, or polymers such as cellulose acetate phthalate which dissolves in response to an increase in pH. Acid is released from the encapsulating agent in response to temperature, pressure, pH, abrasion or combinations thereof. US 6,207,620 also claims the use of non-acid etching agents. Acid may be released from encapsulated acid prematurely if triggering factors such as temperature, pressure, pH or abrasion are encountered during introduction of the encapsulated acid into the fracture and may limit the practical effectiveness of such an approach.

There remains a need for simple and effective processs of acid fracturing in which acid can be efficiently delivered deep into fractures to efficiently etch fracture faces far from the wellbore. This is particularly the case in hot formations where the very fast rate of reaction of conventional mineral and organic acids with carbonate will severely limit the depth to which etching of fracture faces can be achieved. The object of the present invention is to provide a process of fracture acidising a formation penetrated by a well which does not rely on the use of a highly reactive solution of liquid mineral acids or organic acids and so does not suffer from rapid leak-off or from problems arising from the use of reaction retarding agents such as the presence of gel residues or changes in Nettability.

A farther object of the present invention is to provide an alternative process of fracture acidising a formation penetrated by a well based on the use of a solid polymer which hydrolyses to produce organic acid. This acid is then available to react with and etch the fracture faces.

It is a farther object of this invention to provide a process of fracture acidising in which the amount of acid delivered and the rate of delivery of acid to the fracture faces are highly predictable.

Yet a furler object of the invention is to provide a process of fracture acidising in which the polymer will also act as a proppant to keep the fracture open until the fracture faces are sufficiently etched to prevent fracture healing.

Accordingly, the present invention provides a process for the acid fracturing of an underground formation penetrated by a wellbore, which process comprises: (a) injecting a fracturing fluid into the formation under sufficient pressure to fracture the formation, wherein Me fracturing fluid contains a solid polymer capable of being converted by hydrolysis into one or more organic acids; (b) allowing the solid polymer to enter the fracture so generated; and (c) allowing the solid polymer to hydrolyse in the presence of water to produce organic acid within the fracture.

The process of the present invention thus involves fracture acidising an underground formation by introducing into the formation a solid polymer which is converted by hydrolysis into one or more organic acids.

The process of the present invention may be used to increase production from all formations which may benefit from the acid etching of fracture faces. These will primarily be carbonate formations including massive carbonate deposits, but may, exceptionally be sandstone formations such as those with a high carbonate content.

Water and hydrocarbons, for example oil or gas, are generally recovered. The gas may be, for example, natural gas, methane, ethane or butane. The process may also be used to increase the injectivity of injector wells.

Oil, gas or water is recovered from a formation by drilling a wellbore into the coronation and extracting the oil, gas or water. The wellbore serves as a convenient means for introducing the polymer into the formation according to the process of the present invention.

The polymer used in the process of the present invention is any solid polymer which hydrolyses in the presence of water to generate an organic acid or acids.

Preferably the polymer is a polyester, most preferably an aliphatic polyester selected from the group which can be synthesised by suitable processes known to those skilled in Me art, including the ring opening melt condensation of lactide (lactic acid cyclic dimer), glycolide (glycolic acid cyclic dimer) and caprolactone. Hydrolysis of a polymer produced from the condensation of lactide produces lactic acid and hydrolysis of a polymer produced from the condensation of glycolide produces glycolic acid. Lactic acid and glycolic acid (hydroxyacetic) acid are the preferred acids produced by hydrolysis of the polymer used in the process of the present invention.

Suitable polymers include; homopolymers or copolymers of lactic acid and glycolic acid; copolymers of lactic acid and/or glycolic acid with other suitable monomers. Caprolactone is a preferred monomer.

Suitable polymers therefore include polylactide (polylactic acid) polyglycolide (polyglycolic acid) lactide-glycolide copolymer, lactide-caprolactone copolymer, glycolide-caprolactone copolymer or lactide-glycolide- caprolactone copolymer.

Copolymers may also be produced that incorporate compounds other than caprolactone which contain hydroxy-, carboxylic - or hydroxycarboxylic acid moieties. US 4,986,353 provides examples of other suitable monomers with which lactic acid or glycolic acid may be condensed. Suitable monomers include but are not limited to tribasic acids such as citric acid, dibasic acids such as adipic acid, and dials such as ethylene glycol and polyols. They also include difunctional molecules such as 2,2-(bishydroxymethyl) propanoic acid. Preferred co-condensing molecules according to the process of US 4,986,353 are citric acid, 2,2(bishydroxymethyl) propanoic acid, trimethylol-ethane, and adipic acid. The most preferred are lactic acid and citric acid.

Polyesters are the preferred polymers and may incorporate one or more of lactide, glycolide and caprolactone or contain one or more of lactide, glycolide or caprolactone in combination with one or more other monomers as long as the solid polymer undergoes hydrolysis in the presence of water to generate an organic acid or acids. Acid production is from simple hydrolysis of ester linkages in the polyester.

Polymers of different compositions have varied physical and hydrolytic properties, thus permitting the polymer to be tailored to the formation temperature and treatment timing considerations. The composition of the polymer is a principal determinant of the hydrolysis rate and rate of production of acid. A composition which wi11 give the required rate of hydrolysis under the temperature conditions of the treated formation will generally be selected and after generation of the fracture and placement of the polymer the well will be shut in for a time suffcient for the polymer to hydrolyse and produce sufficient acid to etch the fracture faces. The cooling effects of the pad fluid, if used, and the fracturing fluid containing the polymer, will be taken into account in calculating the required shut-in period.

Preferably, the organic acids produced by the hydrolysis of the polymer react with calcium carbonate to form calcium salts with a solubility in water of at least a few percent at the formation temperature. Lactic acid and glycolic acid are suitable acids. The type of organic acid, amount of acid delivered and rate of acid production at a given temperature can be determined by selecting an appropriate polymer composition and form of presentation of the solid polymer (size and shape of the solids).

Hydrolysis of the polymer is by bulk erosion. (Biodegradable Polymers as Drug Delivery Systems, Edited by Mark Chasin and Robert Langer. Marcel Dekker Inc., New York, Basel and Hong Kong, 1990). The rate of hydrolysis is primarily influenced by four key variables, monomer stereochemistry (D or L form), comonomer ratio, polymer chain linearity and polymer molecular weight. Smaller particles of a polymer of a given composition at a given temperature have a larger surface area per unit weight so will produce acid at a faster rate. in general, polylactic acid and other lactic acid rich polymers will degrade at a slower rate than polyglycolic acid and glycolic acid rich polymers. Incorporation of caprolactone into the polymers can further increase the rate of hydrolysis of the polymers. The rate of hydrolysis of the polymers may also be influenced by the extent of block or random structure in copolymers, by chemical modification of the end groups of the polymer or by the introduction of branching into the polymers, for example by incorporating polyols into the polymer.

Because acid is produced from hydrolysis of the polymer over a period of time, the polymer may be placed within the reservoir before most of the acid is produced. Acid is then delivered to the whole zone in which contact with the polymer occurs. In the case of acid fracturing, acid will be delivered to the whole area of the fracture faces, resulting in etching of the fracture faces.

Sufficient polymer is present in the treatment fluid to produce sufficient acid, when the polymer is hydrolysed, to have a substantive etching effect on fracture faces.

The polymer may be used in underground formations at any temperature up to at least the melting temperature of the selected polymer. For example, poly(L-) lactic acid has a melting temperature of about 173 C and polyglycolic acid has a meting point of 230 C. In formations at or above the meltmg temperature of the selected polymer, precooling of the formation by injection of a large volume of water ahead of the fracturing fluid containing the polymer may optionally be employed.

The polymers may be used in any solid configuration, including, but not being limited to spheres, cylinders, cuboids, fibres, powders, beads or any other configuration which can be introduced into the formation. It will preferably be used in the form of particles in the size range 10 microns to 20 mm, most preferably 50 microns to 5 mm.

Polymers of the desired size and shape may be prepared by any suitable process known to those skilled In the art including but not being limited to high shear dispersion of the polymer melt, emulsification followed by solvent evaporation, desolvation, spray drying or grinding. Some suitable processes of producing microparticles, microspheres, microcapsules, shaped particles and fibres are reviewed in Chasin, M and Langer, R. (Eds. ).

Biodegradable Polymers as Drug Delivery Systems. Marcel Dekker Inc., New York, (1990).

US 4,986,355 teaches a process of preparing suitably sized polyester particles for use as a fluid loss additive or as a gel breaker in a subterranean formation. Polymer particles of the present invention are introduced into the formation, at above the fracture pressure, as a slurry or suspension with or without a suspending agent or a viscosifying agent such as borate crosslinked guar gum or any other suitable viscosifying agent. The use of gel systems such as guar-borate which are "broken" (i.e. have their viscosity reduced) by acid produced from hydrolysis of the polymer is preferred, although specific gel breakers such as oxidants or enzymes may also be incorporated into fracturing fluid containing the polymer.

The polymers may also be used as an encapsulating material for other materials, chemicals, catalysts or enzymes. The materials, chemicals, catalysts or enzymes may also be incorporated into the polymers by dissolution or dispersion.

In the case of chemicals encapsulated in the polymer, release will generally be coincident with or after acid production and in the case of dissolved or dispersed chemicals release will be coincident with acid production.

One function of the added materials is to adjust the specific gravity of the polymers to the desired value for the fracturing operation. Preferred materials for adjusting the specific gravity are water-soluble alkali metal salts. Other salts such as those generally used for adjusting the specific gravity of oilfield brines may also be used. The polymer may also be used for the controlled release of chemicals with other functions. In some cases, other acids can be incorporated into the polymers.

For example liquid acids, either mineral or organic, may be encapsulated; or solid acids such as those used in the process of US 3,968,849 may be incorporated, by dissolution or dispersion, into the polymers of the present reaction. Acids other than those arising front the hydrolysis of the polymer will therefore also be released and contribute to the etching of fracture faces.

Other materials, chemicals, catalysts or enzymes encapsulated or incorporated into the polyester polymers by dissolution or dispersion may, singly or in combination, have functional activity or activities, other than as acids for etching of fracture faces, including, but not limited to, as non-acid formation etching agents, gel or polymer breakers, corrosion inhibitors, surfactants, scale inhibitors, chelating agents, scale dissolvers, pour point modifiers, paraffin inhibitors, asphaltene inhibitors, solvents, catalysts or bioactive agents which may be used to address problems associated with hydrocarbon or water production.

A specific function of some chemicals such as quaternary ammonium compounds which may be incorporated into the polyester is to increase the rate of depolymerisation of the polyester (US 5,278,256). Increasing the rate of hydrolysis of the polymers may be desirable in some situations such as the acid fracturing of low temperature formations where the rate of acid production may otherwise be lower than desired.

Because acid is produced by the hydrolysis of the solid polymers, incorporation into the treatment fluid and/or the polymer of chemicals which react with acid to produce oxidants or other chemicals for treatment of the underground formation is convenient. Examples of suitable chemicals are calcium peroxide and ammonium bifluoride. Calcium peroxide decomposes in the presence of acid to form hydrogen peroxide and ammonium bifluoride decomposes in the presence of acid to form hydrogen fluoride. Production of hydrogen peroxide can assist in the oxidative breaking of polymers which may be present in the fracturing fluid and production of hydrogen fluoride permits the dissolution of materials which are not readily soluble in organic acid solutions, such as clays. The ability to produce hydrofluoric acid from combining polymers of the present invention with ammonium bifluoride would not normally be beneficial in a carbonate formation but may be useful if the process is applied to the acid fracturing of sandstone formations containing clays such as illite clays. Situations where the use of the process in sandstone formations may be beneficial will be apparent to those skilled in the art. More than one polymer with or without encapsulated, dissolved or dispersed other materials, chemicals, catalysts or erymes may be introduced into the formation at the same time. For example, a fast dissolving polymer may be selected to give rapid etching of the fracture face. This may be used in combination with another slow dissolving polymer containing scale inhibitor to give controlled release of scale inhibitor to prevent scale deposition during subsequent production operations.

The eventual complete dissolution of the polymer allows ideal clean up behavior. In the practice of the process of the present invention a well is drilled to the subsurface formation to be treated and may be completed by setting casing and tubing and perforating through the casing of the well or any similar process. The completion may also be an openhole completion. A fracture is then formed by any conventional fracturing process in which a suitable fracturing fluid is displaced down the well at a rate that causes the hydraulic pressure on the liquid and the formation to increase until the formation fractures. A pad fluid may be used ahead of the fluid containing the polymers of the present invention. The specific process of fracturing the formation, including whether or not a pad fluid should be used, processes of preparing the polymer suspension, the pump rate to be used and the pressure required to fracture a given formation will be selected by a person of skill in the art and will normally take into account measured characteristics of the formation in question, particularly the fracture pressure.

Generally the fracture fluid carrying the polymer of the present invention will be aqueous. Suitable aqueous fluids include water based fluids such as those based on freshwater, seawater, or brines.

Preferably, the fracture fluid will be a clean fluid, with the only particulate materials present being the polymer. The fracture fluid acts as a carrier fluid and so will normally contain a suspending or viscosifying agent. Suitable agents will be known to those skilled in the art and for aqueous fluids may include polymeric agents, including cross linked polymeric agents, or viscoelastic surfactants. Suspension of the polymer particles in the fracturing fluid assists in placement of the acid yielding polymer into the fracture.

In some cases, it may be desirable to use non aqueous fluids such as hydrocarbons as the fracturing fluid in which case it will be necessary for water to subsequently come into contact with the solid polymer placed in the fracture before hydrolysis of the polymer and acid production can occur For example, in very high temperature formations, placing the polymer in a hydrocarbon fluid may be used to reduce the rate of hydrolysis of the polyester, which is dependent on the presence of water, if the rate of hydrolysis of the polyester would otherwise be regarded as undesirably rapid.

The solid polymer may also be placed using other fluids such as liquid gases.

If liquid carbon dioxide is used, this may permeate through the fracture faces into the formation, mix with the formation water and make carbonic acid, dissolving carbonate rock and increasing the permeability of the formation (US 4,250,965). There remains a need for the polymer placed in the fracture according to the process of the present invention to contact water in order to generate acid. The water may be formation water or water introduced from the surface following the placement of the polymer.

The density of the fracturing fluid will normally be selected to be compatible with its function as a carrier fluid to keep the solid polymer in suspension and facilitate placement of the polymer deep into the fracture. The density of the polymer will be taken into account. Suitable processs of adjusting the density of the fluid are well known to those involved in introducing fluids into underground formations.

The solid polymer is introduced into the formation as a slurry or suspension containing solid polymer in an amount which is compatible with efficient fracturing efficient placement of the polymer-containing fluid and efficient placement of the polymer. The solid polymer may be used at any concentration which will result in sufficient etching of the fracture faces to increase the production rate of the well The concentration will normally be lo. the range of 5% to 60% w/v, preferably 10 to 40%.

The polymer will also act as a fluid loss control agent. Use of polyesters as fluid loss control agents has already been described in US 4,387,769; US 4,526,695 and US 4,715,967.

The fracturing fluid containing the solid polymer is propagated throughout the formation and the solid polymer material is deposited in the formation at all points where the fractures extend. After fractures have been extended to the desired radius from the well bore, injection of the fracturing fluid is stopped and polymer particles are trapped between the fracture faces as the pressure drops and the fracture closes.

At this point the trapped polymer acts as a temporary proppant, hydrolyses and delivers acid to the whole of the fracture faces, even at the extremities of the fractures, resulting in the etching of the fracture faces. The rate of hydrolysis is determined by the composition of the polymer, temperature and size and shape of the polymer particles. The rate of hydrolysis of a polymer of a given composition at a given temperature can be readily determined by one skilled in the art and willbe taken into account in designing the treatment, particularly the shutin time required to etch the fracture faces. The polymer will continue to act as a proppant until it is completely hydrolyzed.

Where the acid or acids generated from hydrolysis of the polymer react with carbonate to form calcium salts with a relatively low solubility, additional water may optionally be introduced into the temporarily propped fracture. The additional water will displace and/or dilute salt- laden water and facilitate the further dissolution of polymer and carbonate. The additional water may be injected from the surface into the fracture at below the fracture pressure of the formation, or where there is sufficient water in the formation, be introduced by putting the well on production for a period sufficient to allow the fracturing fluid to be displaced by formation water. Additional water may be introduced into the fracture once or more than once as needed. In the process of the present invention, conventional acids such as mineral or organic acids may also be included in the fracturing fluid if desired. Ester based fluids such as are described in WO 94/25731 and WO 00/57022 in which water soluble esters are hydrolysed to produce organic acid may also be used in conjunction with the process of the present invention. Mineral or organic acids may be used as a spearhead. They, or water soluble ester based fluids may also be used as the fracturing fluid containing, the solid polymer or may be introduced to the fracture while propped or the etched fracture after the treatment. Use of water soluble ester based fluids will give further acidizing of the fracture. These fluids will be beneficial as they leak off mainly by diffusion and as well as etching the fracture faces will increase the matrix permeability of the formation immediately behind the fracture faces.

The process of the present invention may also be used in conjunction with encapsulated acids such as those taught in the process of US 6,207,620. Any compatible additives normally incorporated into fracture acidising treatments including other fluid loss control agents, corrosion inhibitors, scale inhibitors or similar may also be used in the process of operation of the invention and will not adversely affect its operation.

Optionally, fracturing fluids of the present invention may also contain additional propping agents such as sand, resin or ceramic particles or other materials which act as a propping agent.

The process of the present invention may be used to stimulate any type of well in which acid fracturing is expected to be beneficial in terms of increasing production or injectivity, including vertical, directional or horizontal wells. The wells may be openhole or cased and perforated.

The present invention will be further illustrated in the following Examples:

EXAMPLE 1

1 g of polygiycolic acid powder was added to tubes containing 10 ml of water and 2 g of calcium carbonate (average particle size 50 microns). The tubes were capped and incubated at 25 C, 60 C and 80 C. Calcium carbonate dissolution (due to glycolic acid liberated by hydrolysis of the polyglycolic acid) was monitored by taking samples of the aqueous fluid, separating particulate material by centrifugation and analyzing the soluble calcium using a calorimetric assay process.

The amount of calcium carbonate dissolved after 24 hours was 6, 20 and 40 g/1 at 25 C, 60 C and 80 C respectively.

EXAMPLE 2

1 g of polylactic acid granules (average 2.5 mm diameter) was added to tubes containing 10 ml of water and 2 g of calcium carbonate (average particle size 50 microns). The tubes were capped and incubated at 80 C and 95 C. Calcium carbonate dissolution (due to lactic acid liberated by hydrolysis of the polylactic acid) was monitored by taking samples of the aqueous fluid, separating particulate material by centrifugation and analyzing the soluble calcium using a calorimetric assay process.

The amount of calcium carbonate dissolved after 24 hours was 2.5 and 12.4 g/l at 80 C and 95 C; respectively.

The Examples show that calcium carbonate is dissolved by acid produced from the hydrolysis of the solid polymers. They further show that the rate of acid production is a function of the composition of the polymer and the temperature. Organic acid production from the polymers within a fracture in a carbonate formation will result in etching of the fracture face, which is a carbonate surface.

Claims

I. A process for the acid fracturing of an underground formation penetrated by a wellbore, which process comprises: (a) injecting a fracturing fluid into the formation under sufficient pressure to fracture the formation, wherein the fracturing fluid contains a solid polymer capable of being converted by hydrolysis into one or more organic acids; (b) allowing the solid polymer to enter the fracture so generated; and (c) allowing the solid polymer to hydrolyse in the presence of water to produce organic acid within the fracture.
2. A process according to claim 1 wherein the polymer is a polyester.
3. A process according to claim 1 or 2 wherein the polymer is an aliphatic polyester.
4. A process according to any one of claims 1, 2 and 3 wherein the polymer is polylactide, polyglycolide, lactide-glycolide copolymer, lactide-caprolactone copolymer, glycolide-caprolactone copolymer or lactide-glycolide-caprolactone copolymer.
5. A process according to claim 1 wherein the polymer is a polymer which incorporates lactide, glycolide or caprolactone.
6. A process according to claim 1 wherein the polymer is a polymer which incorporates lactide, glycolide or caprolactone with other monomers.
7. A process according to any one of the preceding claims wherein hydrolysis of the polymer produces one or more organic acids.
8. A process according to any one of the preceding claims wherein hydrolysis of the polymer produces lactic acid or glycolic acid.
9. A process according to any one of the preceding claims wherein one or more other materials, chemicals, catalysts or enzymes are incorporated into the polymer by encapsulation to allow their controlled release coincident with or after acid production.
10. A process according to any one of the preceding claims wherein the said one or more other materials, chemicals, catalysts or enzymes are incorporated into the polymer by dissolution or dispersion to alloy' their controlled release coincident with acid production.
11. A process according to claim 9 or 10 where the said one or more other materials, chemicals, catalysts or erymes released from the polymer have functional activity or activities with application in hydrocarbon or water production.
12. A process according to claim 1 1 wherein the said other fimctional activity or activities include activity as acids, other etching agents, gel or polymer breakers, corrosion inhibitors, surfactants, scale inhibitors, chelating agents, scale dissolvers, paraffin inhibitors, asphaltene inhibitors, pour point modifiers, solvents, catalysts or bioactive agents.
13. A process according to any one of claims 9 to 12 wherein the said one or more other materials, chemicals, catalysts or enzymes are used for treating problems associated with hydrocarbon or water production.
14. A process according to any one of the preceding claims wherein the solid form of the polymer is a sphere, cylinder, cuboid, fibre, powder, bead or other configuration.
15. A process according to any one of the preceding claims wherein the polymer also functions as a proppant.
16. A process according to any one of the preceding claims wherein the polymer is introduced in a combination with other encapsulating agents, diverting agents or proppants.
17. A process according to any one of the preceding claims wherein at least a portion of the polymer remains in the Coronation and continuously releases organic acid and other materials, chemicals, catalysts or enzymes used for treating problems associated with hydrocarbon or water production.
18. A process according to any one of the preceding claims wherein the underground formation contains hydrocarbon or water.
19. A process according to claim 18 wherein the underground formation contains hydrocarbon and wherein the process further comprises recovering a hydrocarbon from the acidised formation.
20. A process according to claim 18 wherein the underground formation contains water and wherein the process further comprises recovering water Tom the acidised formation.
21. A process according to any one of the preceding claims wherein the polymer is introduced into the formation via a well bore which extends to the formation.
22. A process according to any of the previous claims wherein the polymer is used in conjunction with another acid system.
23. A process according to claim 22 wherein the said acid system comprises a solution which contains or generates mineral and/or organic acids.
24. A process according to arty one of the preceding claims wherein the fracturing fluid comprises a viscosifying agent and wherein the viscosity of the fluid is reduced by the acid generated by hydrolysis of the solid polymer.
25. A process according to claim 24 wherein the viscosifying agent is borate crosslinked guar gum.
26. A process according to any one of the preceding claims wherein the fracturing fluid contains the solid polymer in an amount of from 5% - 60% w/v.