Process to treat subterranean formations using a chelating agent

Abstract

The present invention relates to a process to treat a subterranean formation by introducing a composition containing between 1 and 40 wt % on total weight of the composition of a chelating agent selected from the group of glutamic acid N,N-diacetic acid or a salt thereof (GLDA), aspartic acid N,N-diacetic acid or a salt thereof (ASDA), and methylglycine N,N-diacetic acid or a salt thereof (MGDA) into the formation, wherein the process comprises a soaking step.

Claims

1. Process to treat a subterranean formation by introducing a composition containing between 1 and 40 wt % on total weight of the composition of a chelating agent selected from the group of glutamic acid N,N-diacetic acid or a salt thereof (GLDA), aspartic acid N,N-diacetic acid or a salt thereof (ASDA), and methylglycine N,N-diacetic acid or a salt thereof (MGDA) into the formation at an original flow rate in an original direction, wherein the process comprises a soaking step wherein the flow rate of the composition is purposively decreased from the original flow rate for a period of time, and then increased, said increased flow being in either the original direction or a different direction.

2. Process of claim 1, wherein the temperature during the process is between 77 and 400° F. (about 25 and 204° C.).

3. Process of claim 1, wherein the formation is a carbonate formation, a sandstone formation, an illitic formation, or a shale formation having a dissolution rate in the composition of less than 5.Math.10.sup.−6 gmole/cm.sup.2.Math.s at 121° C.

4. Process of claim 1, wherein the formation is a carbonate formation, a sandstone formation, an illitic formation, or a shale formation having an initial permeability of less than 10 mD.

5. Process of claim 1, containing more than one soaking step.

6. Process of claim 1, wherein the composition in addition contains a further additive from the group of foam extenders, crosslinking agents, anti-sludge agents, surfactants, corrosion inhibitors, mutual solvents, corrosion inhibitor intensifiers, foaming agents, viscosifiers, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, viscosity stabilizers, rheology modifiers, gelling agents, scale inhibitors, breakers, salts, brines, pH control additives, bactericides/biocides, particulates, crosslinkers, relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, and consolidating agents.

7. Process of claim 1, wherein the pH of the composition is between 2 and 5.

8. Process of claim 1 that is a matrix-acidizing process or an acid-fracturing process.

9. Process of claim 8, wherein at the same time the wellbore is cleaned or descaling of equipment used in the process or descaling of the wellbore takes place.

Description

(1) Example:

(2) Decylalcohol ethoxylate (8EO): C.sub.10-EO.sub.8

(3) Hydrophobic part: CH.sub.3(CH.sub.2).sub.9—OH molar mass=158

(4) Hydrophilic part: [CH.sub.2CH.sub.2O].sub.8 molar mass=352

(5) HLB for C.sub.10-EO.sub.8 is 20×352/(352+158)=13.8

(6) The HLB of surfactants having ionic portions is calculated by Davis's formula rather than Griffin's:

(7) HLB=7+Σ(Hydrophilic group contributions)−Σ(Hydrophobic group contributions), in which case the following tables need to be used in finding the increments, see Tables A-D in Technical Information Surface Chemistry: HLB & Emulsification, link: http://www.scribd.com/doc/56449546/HLB-Emulsification.

(8) Table A has been retrieved:

(9) TABLE-US-00001 TABLE A anionic hydrophilic group contributions hydrophilic group HLB contribution —COO—Na.sup.+ 19.1 —SO.sub.3—Na.sup.+ 20.7 —O—SO.sub.3—Na.sup.+ 20.8
Example:
Tetradecyl ammonium chloride: C.sub.14—N(CH.sub.3).sub.3.sup.+Cl.sup.−
Group contributions of the hydrophobic groups:
—CH3: 1×0.475
—CH2-: 13×0.475
Group contributions of the hydrophilic groups:
—N(CH.sub.3).sub.3.sup.+Cl.sup.−22.0
HLB for C.sub.14—N(CH.sub.3).sub.3.sup.+Cl.sup.− is 7+22.0−(14×0.475)=22.4

(10) The HLB of surfactant mixtures is simply the weight average of the HLBs of the individual surfactant types.

(11) In one embodiment the HLB of the emulsifying agent is about 20 or below; alternatively, the HLB is about 10 or below; and in another embodiment it is about 8 or below.

(12) In another embodiment, a suitable emulsion is obtained by including polymeric surfactants as emulsifiers. Examples of polymeric surfactants are partially hydrolyzed polyvinyl acetate, partially hydrolyzed modified polyvinyl acetate, block or co-polymers of alkenes such as polyethylene, polypropylene, polybutylene or polypentylene, proteins, and partially hydrolyzed polyvinyl acetate, polyacrylate and derivatives of polyacrylates, polyvinyl pyrrolidone and derivatives. The additional application of further surfactants to the polymeric surfactant is beneficial to the emulsion quality or lifetime.

(13) Examples of emulsifiers include, but are not limited to, quaternary ammonium compounds (e.g., trimethyl tallow ammonium chloride, trimethyl coco ammonium chloride, dimethyl dicoco ammonium chloride, etc.), derivatives thereof, and combinations thereof, low HLB surfactants or oil-soluble surfactants. More specific suitable emulsifiers include, but are not necessarily limited to, polysorbates, alkyl sulfosuccinates, alkyl phenols, ethoxylated alkyl phenols, alkyl benzene sulfonates, fatty acids, ethoxylated fatty acids, propoxylated fatty acids, fatty acid salts, tall oils, castor oils, triglycerides, ethoxylated triglycerides, alkyl glucosides, and mixtures and derivatized fatty acids such as those disclosed in U.S. Pat. No. 6,849,581. Suitable polysorbates include, but are not necessarily limited to, sorbitan monolaurate, sorbitan monopalmitate, sorbitan monostearate, sorbitan monooleate, sorbitan monodecanoate, sorbitan monooctadecanoate, sorbitan trioleate and the like, and ethoxylated derivatives thereof. For instance, emulsifiers may have up to 20 ethoxy groups thereon. Suitable emulsifiers include stearyl alcohol, lecithin, fatty acid amines, ethoxylated fatty acid amines, and mixtures thereof. In some embodiments, more than one emulsifier may be used. Preferably, the emulsifier is cationic, such as an emulsifier that contains quaternary ammonium group-containing components.

(14) The mutual solvent is a chemical additive that is soluble in oil, water, acids (often HCl-based), and other well treatment fluids (see also www.glossary.oilfield.slb.com). Mutual solvents are routinely used in a range of applications, controlling the wettability of contact surfaces before, during and/or after a treatment, and preventing or breaking up emulsions. Mutual solvents are used, as insoluble formation fines pick up organic film from crude oil. These particles are partially oil-wet and partially water-wet. This causes them to collect materials at any oil-water interface, which can stabilize various oil-water emulsions. Mutual solvents remove organic films leaving them water-wet, thus emulsions and particle plugging are eliminated. If a mutual solvent is employed, it is preferably selected from the group which includes, but is not limited to, lower alcohols such as methanol, ethanol, 1-propanol, 2-propanol, and the like, glycols such as ethylene glycol, propylene glycol, diethylene glycol, dipropylene glycol, polyethylene glycol, polypropylene glycol, polyethylene glycol-polyethylene glycol block copolymers, and the like, and glycol ethers such as 2-methoxyethanol, diethylene glycol monomethyl ether, and the like, substantially water/oil-soluble esters, such as one or more C2-esters through C10-esters, and substantially water/oil-soluble ketones, such as one or more C2-C10 ketones, wherein substantially soluble means soluble in more than 1 gram per liter, preferably more than 10 grams per liter, even more preferably more than 100 grams per liter, most preferably more than 200 grams per liter. The mutual solvent is preferably present in an amount of 1 to 50 wt % on total composition.

(15) A preferred water/oil-soluble ketone is methylethyl ketone.

(16) A preferred substantially water/oil-soluble alcohol is methanol.

(17) A preferred substantially water/oil-soluble ester is methyl acetate.

(18) A more preferred mutual solvent is ethylene glycol monobutyl ether, generally known as EGMBE

(19) The amount of glycol solvent in the composition is preferably about 1 wt % to about 10 wt %, more preferably between 3 and 5 wt %. More preferably, the ketone solvent may be present in an amount from 40 wt % to about 50 wt %; the substantially water-soluble alcohol may be present in an amount within the range of about 20 wt % to about 30 wt %; and the substantially water/oil-soluble ester may be present in an amount within the range of about 20 wt % to about 30 wt %, each amount being based upon the total weight of the solvent in the composition.

(20) The surfactant (water-wetting surfactants as well as surfactants used as foaming agent, viscosifying agent or emulsifying agent) can be any surfactant known in the art and includes anionic, cationic, amphoteric, and nonionic surfactants. The choice of surfactant is initially determined by the nature of the rock formation around the well. The application of cationic surfactants is best limited in the case of sandstone, while in the case of carbonate rock, anionic surfactants are not preferred. Hence, the surfactant (mixture) is predominantly anionic in nature when the formation is a sandstone formation. When the formation is a carbonate formation, the surfactant (mixture) is preferably predominantly nonionic or cationic in nature, even more preferably predominantly cationic.

(21) The nonionic surfactant of the present composition is preferably selected from the group consisting of alkanolamides, alkoxylated alcohols, alkoxylated amines, amine oxides, alkoxylated amides, alkoxylated fatty acids, alkoxylated fatty amines, alkoxylated alkyl amines (e.g., cocoalkyl amine ethoxylate), alkyl phenyl polyethoxylates, lecithin, hydroxylated lecithin, fatty acid esters, glycerol esters and their ethoxylates, glycol esters and their ethoxylates, esters of propylene glycol, sorbitan, ethoxylated sorbitan, polyglycosides, and the like, and mixtures thereof. Alkoxylated alcohols, preferably ethoxylated alcohols, optionally in combination with (alkyl) polyglycosides, are the most preferred nonionic surfactants.

(22) The anionic surfactants may comprise any number of different compounds, including alkyl sulfates, alkyl sulfonates, alkylbenzene sulfonates, alkyl phosphates, alkyl phosphonates, alkyl sulfosuccinates.

(23) The amphoteric surfactants include hydrolyzed keratin, taurates, sultaines, phosphatidyl cholines, betaines, modified betaines, alkylamidobetaines (e.g., cocoamidopropyl betaine).

(24) The cationic surfactants include alkyl amines, alkyl dimethylamines, alkyl trimethylamines (quaternary amines), alkyl diethanolamines, dialkyl amines, dialkyl dimethylamines, and less common classes based on phosphonium, sulfonium. In preferred embodiments, the cationic surfactants may comprise quaternary ammonium compounds (e.g., trimethyl tallow ammonium chloride, trimethyl coco ammonium chloride), derivatives thereof, and combinations thereof.

(25) Examples of surfactants that are also foaming agents that may be utilized to foam and stabilize the treatment compositions of this invention include, but are not limited to, betaines, amine oxides, methyl ester sulfonates, alkylamidobetaines such as cocoamidopropyl betaine, alpha-olefin sulfonate, trimethyl tallow ammonium chloride, C8 to C22 alkyl ethoxylate sulfate, and trimethyl coco ammonium chloride.

(26) The foaming agent, if used, is normally used in an amount of between 10 and 200,000 ppm based on the total weight of the composition, preferably between 100 and 10,000 ppm.

(27) Suitable surfactants may be used in a liquid or solid form, like a powder, granule or particulate form.

(28) Where used, the surfactants may be present in the composition in an amount sufficient to prevent incompatibility with formation fluids, other treatment fluids, or wellbore fluids at reservoir temperature.

(29) In an embodiment where liquid surfactants are used, the surfactants are generally present in an amount in the range of from about 0.01% to about 5.0% by volume of the composition.

(30) In one embodiment, the liquid surfactants are present in an amount in the range of from about 0.1% to about 2.0% by volume of the composition, more preferably between 0.1 and 1 vol %.

(31) In embodiments where powdered surfactants are used, the surfactants may be present in an amount in the range of from about 0.001% to about 0.5% by weight of the composition.

(32) The anti-sludge agent can be chosen from the group of mineral and/or organic acids used to stimulate sandstone hydrocarbon-bearing formations. The function of the acid is to dissolve acid-soluble materials so as to clean or enlarge the flow channels of the formation leading to the wellbore, allowing more oil and/or gas to flow to the wellbore.

(33) Problems can be caused by the interaction of the (usually concentrated, 20-28%) stimulation acid and certain crude oils (e.g. asphaltic oils) in the formation to form sludge. Interaction studies between sludging crude oils and the introduced acid show that permanent rigid solids are formed at the acid-oil interface when the aqueous phase is below a pH of about 4. No films are observed for non-sludging crudes with acid.

(34) These sludges are usually reaction products formed between the acid and the high molecular weight hydrocarbons such as asphaltenes, resins, etc.

(35) Methods for preventing or controlling sludge formation with its attendant flow problems during the acidization of crude-containing formations include adding “anti-sludge” agents to prevent or reduce the rate of formation of crude oil sludge, which anti-sludge agents stabilize the acid-oil emulsion and include alkyl phenols, fatty acids, and anionic surfactants. Frequently used as the surfactant is a blend of a sulfonic acid derivative and a dispersing surfactant in a solvent. Such a blend generally has dodecyl benzene sulfonic acid (DDBSA) or a salt thereof as the major dispersant, i.e. anti-sludge, component.

(36) The carrier fluids are aqueous solutions which in certain embodiments contain a Bronsted acid to keep the pH in the desired range and/or contain an inorganic salt, preferably NaCl or KCl.

(37) Corrosion inhibitors may be selected from the group of amine and quaternary ammonium compounds and sulfur compounds. Examples are diethyl thiourea (DETU), which is suitable up to 185° F. (about 85° C.), alkyl pyridinium or quinolinium salt, such as dodecyl pyridinium bromide (DDPB), and sulfur compounds, such as thiourea or ammonium thiocyanate, which are suitable for the range 203-302° F. (about 95-150° C.), benzotriazole (BZT), benzimidazole (BZI), dibutyl thiourea, a proprietary inhibitor called TIA, and alkyl pyridines.

(38) In general, the most successful inhibitor formulations for organic acids and chelating agents contain amines, reduced sulfur compounds or combinations of a nitrogen compound (amines, quats or polyfunctional compounds) and a sulfur compound. The amount of corrosion inhibitor is preferably between 0.1 and 2 vol %, more preferably between 0.1 and 1 vol % on the total composition.

(39) One or more corrosion inhibitor intensifiers may be added, such as for example formic acid, potassium iodide, antimony chloride, or copper iodide.

(40) One or more salts may be used as rheology modifiers to further modify the rheological properties (e.g., viscosity and elastic properties) of the compositions. These salts may be organic or inorganic.

(41) Examples of suitable organic salts include, but are not limited to, aromatic sulfonates and carboxylates (such as p-toluene sulfonate and naphthalene sulfonate), hydroxynaphthalene carboxylates, salicylate, phthalate, chlorobenzoic acid, phthalic acid, 5-hydroxy-1-naphthoic acid, 6-hydroxy-1-naphthoic acid, 7-hydroxy-1-naphthoic acid, 1-hydroxy-2-naphthoic acid, 3-hydroxy-2-naphthoic acid, 5-hydroxy-2-naphthoic acid, 7-hydroxy-2-naphthoic acid, 1,3-dihydroxy-2-naphthoic acid, 3,4-dichlorobenzoate, trimethyl ammonium hydrochloride, and tetramethyl ammonium chloride.

(42) Examples of suitable inorganic salts include water-soluble potassium, sodium, and ammonium halide salts (such as potassium chloride and ammonium chloride), calcium chloride, calcium bromide, magnesium chloride, sodium formate, potassium formate, cesium formate, and zinc halide salts. A mixture of salts may also be used, but it should be noted that preferably chloride salts are mixed with chloride salts, bromide salts with bromide salts, and formate salts with formate salts.

(43) Wetting agents that may be suitable for use in this invention include crude tall oil, oxidized crude tall oil, surfactants, organic phosphate esters, modified imidazolines and amidoamines, alkyl aromatic sulfates and sulfonates, and the like, and combinations or derivatives of these and similar such compounds that should be well known to one of skill in the art.

(44) Examples of suitable brines include calcium bromide brines, zinc bromide brines, calcium chloride brines, sodium chloride brines, sodium bromide brines, potassium bromide brines, potassium chloride brines, sodium nitrate brines, sodium formate brines, potassium formate brines, cesium formate brines, magnesium chloride brines, sodium sulfate, potassium nitrate, and the like. A mixture of salts may also be used in the brines, but it should be noted that preferably chloride salts are mixed with chloride salts, bromide salts with bromide salts, and formate salts with formate salts.

(45) The brine chosen should be compatible with the formation and should have a sufficient density to provide the appropriate degree of well control.

(46) Additional salts may be added to a water source, e.g., to provide a brine, and a resulting treatment composition, in order to have a desired density.

(47) The amount of salt to be added should be the amount necessary for formation compatibility, such as the amount necessary for the stability of clay minerals, taking into consideration the crystallization temperature of the brine, e.g., the temperature at which the salt precipitates from the brine as the temperature drops.

(48) Preferred suitable brines may include seawater and/or formation brines.

(49) Salts may optionally be included in the composition of the present invention for many purposes, including for reasons related to compatibility of the composition with the formation and the formation fluids.

(50) To determine whether a salt may be beneficially used for compatibility purposes, a compatibility test may be performed to identify potential compatibility problems.

(51) From such tests, one of ordinary skill in the art will, with the benefit of this disclosure, be able to determine whether a salt should be included in a composition of the present invention.

(52) Suitable salts include, but are not limited to, calcium chloride, sodium chloride, magnesium chloride, potassium chloride, sodium bromide, potassium bromide, ammonium chloride, sodium formate, potassium formate, cesium formate, and the like. A mixture of salts may also be used, but it should be noted that preferably chloride salts are mixed with chloride salts, bromide salts with bromide salts, and formate salts with formate salts.

(53) The amount of salt to be added should be the amount necessary for the required density for formation compatibility, such as the amount necessary for the stability of clay minerals, taking into consideration the crystallization temperature of the brine, e.g., the temperature at which the salt precipitates from the brine as the temperature drops.

(54) Salt may also be included to increase the viscosity of the composition and stabilize it, particularly at temperatures above 180° F. (about 82° C.).

(55) Examples of suitable pH control additives which may optionally be included in the composition of the present invention are acids and/or bases.

(56) A pH control additive may be necessary to maintain the pH of the composition at a desired level, e.g., to improve the effectiveness of certain breakers and to reduce corrosion on any metal present in the wellbore or formation, etc.

(57) One of ordinary skill in the art will, with the benefit of this disclosure, be able to recognize a suitable pH for a particular application.

(58) In one embodiment, the pH control additive may be an acidic composition.

(59) Examples of suitable acids may comprise an acid, an acid-generating compound, and combinations thereof.

(60) Any known acid may be suitable for use with the compositions of the present invention.

(61) Examples of acids that may be suitable for use in the present invention include, but are not limited to, organic acids (e.g., formic acids, acetic acids, carbonic acids, citric acids, glycolic acids, lactic acids, p-toluene sulfonic acid, ethylene diamine tetraacetic acid (EDTA), hydroxyethyl ethylene diamine triacetic acid (HEDTA), and the like), inorganic acids (e.g., hydrochloric acid, hydrofluoric acid, phosphonic acid, and the like), and combinations thereof. Preferred acids are HCl (in an amount compatible with the illite content) and organic acids.

(62) Examples of acid-generating compounds that may be suitable for use in the present invention include, but are not limited to, esters, aliphatic polyesters, ortho esters, which may also be known as ortho ethers, poly(ortho esters), which may also be known as poly(ortho ethers), poly(lactides), poly(glycolides), poly(epsilon-caprolactones), poly(hydroxybutyrates), poly(anhydrides), or copolymers thereof.

(63) Derivatives and combinations also may be suitable.

(64) The term “copolymer” as used herein is not limited to the combination of two polymers, but includes any combination of polymers, e.g., terpolymers and the like. Other suitable acid-generating compounds include: esters including, but not limited to, ethylene glycol monoformate, ethylene glycol diformate, diethylene glycol diformate, glyceryl monoformate, glyceryl diformate, glyceryl triformate, methylene glycol diformate, and formate esters of pentaerythritol.

(65) The pH control additive also may comprise a base to elevate the pH of the composition.

(66) Generally, a base may be used to elevate the pH of the mixture to greater than or equal to about 7.

(67) Having the pH level at or above 7 may have a positive effect on a chosen breaker being used and may also inhibit the corrosion of any metals present in the wellbore or formation, such as tubing, screens, etc.

(68) In addition, having a pH greater than 7 may also impart greater stability to the viscosity of the treatment composition, thereby enhancing the length of time that viscosity can be maintained.

(69) This could be beneficial in certain uses, such as in longer-term well control and in diverting.

(70) Any known base that is compatible with the components in the emulsified compositions of the present invention can be used in the emulsified compositions of the present invention.

(71) Examples of suitable bases include, but are not limited to, sodium hydroxide, potassium carbonate, potassium hydroxide, sodium carbonate, and sodium bicarbonate.

(72) One of ordinary skill in the art will, with the benefit of this disclosure, recognize the suitable bases that may be used to achieve a desired pH elevation.

(73) In some embodiments, the composition may optionally comprise a further chelating agent.

(74) When added, the chelating agent may chelate any dissolved iron (or other divalent or trivalent cations) that may be present and prevent any undesired reactions being caused.

(75) Such a chelating agent may, e.g., prevent such ions from crosslinking the gelling agent molecules.

(76) Such crosslinking may be problematic because, inter alia, it may cause filtration problems, injection problems and/or again cause permeability problems.

(77) Any suitable chelating agent may be used with the present invention.

(78) Examples of suitable chelating agents include, but are not limited to, citric acid, nitrilotriacetic acid (NTA), any form of ethylene diamine tetraacetic acid (EDTA), diethylene triamine pentaacetic acid (DTPA), propylene diamine tetraacetic acid (PDTA), ethylene diamine-N,N″-di(hydroxyphenyl) acetic acid (EDDHA), ethylene diamine-N,N″-di-(hydroxy-methylphenyl) acetic acid (EDDHMA), ethanol diglycine (EDG), trans-1,2-cyclohexylene dinitrilotetraacetic acid (CDTA), glucoheptonic acid, gluconic acid, sodium citrate, phosphonic acid, salts thereof, and the like.

(79) In some embodiments, the chelating agent may be a sodium or potassium salt.

(80) Generally, the chelating agent may be present in an amount sufficient to prevent undesired side effects of divalent or trivalent cations that may be present, and thus also functions as a scale inhibitor.

(81) One of ordinary skill in the art will, with the benefit of this disclosure, be able to determine the proper concentration of a chelating agent for a particular application.

(82) In some embodiments, the compositions of the present invention may contain bactericides or biocides, inter alia, to protect the subterranean formation as well as the composition from attack by bacteria. Such attacks can be problematic because they may lower the viscosity of the composition, resulting in poorer performance, such as poorer sand suspension properties, for example.

(83) Any bactericides known in the art are suitable. Biocides and bactericides that protect against bacteria that may attack GLDA, ASDA, or MGDA are preferred, in addition to bactericides or biocides that control or reduce typical downhole microorganisms, like sulfate reducing bacteria (SRB).

(84) An artisan of ordinary skill will, with the benefit of this disclosure, be able to identify a suitable bactericide and the proper concentration of such bactericide for a given application.

(85) Examples of suitable bactericides and/or biocides include, but are not limited to, phenoxyethanol, ethylhexyl glycerine, benzyl alcohol, benzyl alkonium, methyl chloroisothiazolinone, methyl isothiazolinone, methyl paraben, ethyl paraben, propylene glycol, bronopol, benzoic acid, imidazolinidyl urea, a 2,2-dibromo-3-nitrilopropionamide, and a 2-bromo-2-nitro-1,3-propane diol. In one embodiment, the bactericides are present in the composition in an amount in the range of from about 0.001% to about 1.0% by weight of the composition.

(86) Compositions of the present invention also may comprise breakers capable of assisting in the reduction of the viscosity of the composition at a desired time.

(87) Examples of such suitable breakers for the present invention include, but are not limited to, oxidizing agents such as sodium chlorites, sodium bromate, hypochlorites, perborate, persulfates, and peroxides, including organic peroxides. Other suitable breakers include, but are not limited to, suitable acids and peroxide breakers, triethanol amine, as well as enzymes that may be effective in breaking. The breakers can be used as is or encapsulated.

(88) Examples of suitable acids may include, but are not limited to, hydrochloric acid, hydrofluoric acid, formic acid, acetic acid, citric acid, lactic acid, glycolic acid, chlorous acid, etc.

(89) A breaker may be included in the composition of the present invention in an amount and form sufficient to achieve the desired viscosity reduction at a desired time.

(90) The breaker may be formulated to provide a delayed break, if desired.

(91) The compositions of the present invention also may comprise suitable fluid loss additives.

(92) Such fluid loss additives may be particularly useful when a composition of the present invention is used in a fracturing application or in a composition that is used to seal a formation against invasion of fluid from the wellbore.

(93) Any fluid loss agent that is compatible with the compositions of the present invention is suitable for use in the present invention.

(94) Examples include, but are not limited to, starches, silica flour, gas bubbles (energized fluid or foam), benzoic acid, soaps, resin particulates, relative permeability modifiers, degradable gel particulates, diesel or other hydrocarbons dispersed in fluid, and other immiscible fluids.

(95) Another example of a suitable fluid loss additive is one that comprises a degradable material.

(96) Suitable examples of degradable materials include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(glycolide-co-lactides); poly(epsilon-caprolactones); poly(3-hydroxybutyrates); poly(3-hydroxybutyrate-co-hydroxyvalerates); poly(anhydrides); aliphatic poly(carbonates); poly(ortho esters); poly(amino acids); poly(ethylene oxides); poly(phosphazenes); derivatives thereof; or combinations thereof.

(97) In some embodiments, a fluid loss additive may be included in an amount of about 5 to about 2,000 lbs/Mgal (about 600 to about 240,000 g/Mliter) of the composition.

(98) In some embodiments, the fluid loss additive may be included in an amount from about 10 to about 50 lbs/Mgal (about 1,200 to about 6,000 g/Mliter) of the composition.

(99) In certain embodiments, a stabilizer may optionally be included in the compositions of the present invention.

(100) It may be particularly advantageous to include a stabilizer if a (too) rapid viscosity degradation is experienced.

(101) One example of a situation where a stabilizer might be beneficial is where the BHT (bottom hole temperature) of the wellbore is sufficient to break the composition by itself without the use of a breaker.

(102) Suitable stabilizers include, but are not limited to, sodium thiosulfate, methanol, and salts such as formate salts and potassium or sodium chloride.

(103) Such stabilizers may be useful when the compositions of the present invention are utilized in a subterranean formation having a temperature above about 200° F. (about 93° C.). If included, a stabilizer may be added in an amount of from about 1 to about 50 lbs/Mgal (about 120 to about 6,000 g/Mliter) of the composition.

(104) Scale inhibitors may be added, for example, when the compositions of the invention are not particularly compatible with the formation waters in the formation in which they are used.

(105) These scale inhibitors may include water-soluble organic molecules with carboxylic acid, aspartic acid, maleic acids, sulfonic acids, phosphonic acid, and phosphate ester groups including copolymers, ter-polymers, grafted copolymers, and derivatives thereof.

(106) Examples of such compounds include aliphatic phosphonic acids such as diethylene triamine penta (methylene phosphonate) and polymeric species such as polyvinyl sulfonate.

(107) The scale inhibitor may be in the form of the free acid but is preferably in the form of mono- and polyvalent cation salts such as Na, K, Al, Fe, Ca, Mg, NH.sub.4. Any scale inhibitor that is compatible with the composition in which it will be used is suitable for use in the present invention.

(108) Suitable amounts of scale inhibitors that may be included may range from about 0.05 to 100 gallons per about 1,000 gallons (i.e. 0.05 to 100 liters per 1,000 liters) of the composition.

(109) Any particulates such as proppant, gravel that are commonly used in subterranean operations may be used in the present invention (e.g., sand, gravel, bauxite, ceramic materials, glass materials, wood, plant and vegetable matter, nut hulls, walnut hulls, cotton seed hulls, cement, fly ash, fibrous materials, composite particulates, hollow spheres and/or porous proppant).

(110) It should be understood that the term “particulate” as used in this disclosure includes all known shapes of materials including substantially spherical materials, oblong, fibre-like, ellipsoid, rod-like, polygonal materials (such as cubic materials), mixtures thereof, derivatives thereof, and the like.

(111) In some embodiments, coated particulates may be suitable for use in the treatment compositions of the present invention. It should be noted that many particulates also act as diverting agents. Further diverting agents are viscoelastic surfactants and in-situ gelled fluids.

(112) Oxygen scavengers may be needed to enhance the thermal stability of the GLDA, ASDA, or MGDA. Examples thereof are sulfites and ethorbates.

(113) Friction reducers can be added in an amount of up to 0.2 vol %. Suitable examples are viscoelastic surfactants and enlarged molecular weight polymers.

(114) Further crosslinkers can be chosen from the group of multivalent cations that can crosslink polymers such as Al, Fe, B, Ti, Cr, and Zr, or organic crosslinkers such as polyethylene amines, formaldehyde.

(115) Sulfide scavengers can suitably be an aldehyde or ketone.

(116) Viscoelastic surfactants can be chosen from the group of amine oxides, carboxyl butane-based surfactants, or betaine surfactants.

(117) High-temperature applications may benefit from the presence of an oxygen scavenger in an amount of less than about 2 vol % of the solution.

(118) In the process of the invention, the composition can be flooded back from the formation. Even more preferably, (part of) the composition is recycled.

(119) It must be realized, however, that GLDA, ASDA and MGDA, being biodegradable chelating agents, will not flow back completely and therefore are not recyclable to the full extent.

(120) The invention is further illustrated by the Examples below.

EXAMPLES

Experiments 1-6

(121) GLDA with a concentration of 20 wt % and pH of 3.8 was prepared from an original solution of Dissolvine® GL-NA-36-S obtained from AkzoNobel. The original GLDA concentration was 38 wt %. Deionized water, obtained from a water purification system, which has a resistivity of 18.2 MΩ.Math.cm at room temperature, was used to prepare the 20 wt % GLDA solution.

(122) Dolomite cores were obtained from a quarry. XRD and XRF analyses confirmed that the composition of the cores was almost fully dolomite with a dissolution rate of about 5.Math.10.sup.−7 gmole/cm.sup.2.Math.s at 250° F. (121° C.). The cores were 3.6 inches (9.14 cm) long and 1.5 inches (3.81 cm) in diameter. Prior to treatment, they were dried and the dry weight was measured. Subsequently, they were saturated with deionized water and their pore volume (PV) and initial permeability were measured.

(123) The static coreflood experiments were performed at a back pressure of 1,100 PSI (75.8 bar) and an overburden pressure of 1,600 PSI (110.3 bar), whereas the dynamic coreflood experiments were performed at 1,400 PSI (96.5 bar) and 1,900 PSI (131 bar), respectively. All coreflood experiments were performed at a temperature of 275° F. (135° C.).

(124) Furthermore, the initial and final permeabilities ki and kf, respectively, were determined using water at room temperature, a back pressure of 500 PSI (34.4 bar), and an overburden pressure of 800 PSI (55.2 bar) before and after the treatments. The pressure drop was used to calculate the permeabilities using Darcy's law for laminar, linear, and steady-state flow of Newtonian fluids in porous media:
k=(122,81qμL)/(ΔpD.sup.2)
where k is the core permeability [md], q is the flow rate [cm3/min], μ is the fluid viscosity [cP], L is the core length [in], Δp is the pressure drop across the core [psi], and D is the core diameter [in].

(125) Coreflood experiments comparing static treatments (soaking) with dynamic treatments (flow) were executed using a 20 wt % GLDA solution. During the static treatments the injection valve was closed for a certain amount of time (1-6 hr) after dosing 1 PV of GLDA solution, without releasing the pressure. After the soaking time the GLDA solution was washed from the core with water. In some cases this treatment was repeated several times with a fresh dose of GLDA solution. The dynamic treatment was performed with an injection rate of 1 ml/min.

Experiment 1: Dynamic Treatment

(126) A dynamic coreflood experiment was done with the dolomite core in which in total 14 PV of GLDA solution was dosed in nearly 7 hours. After the treatment, face dissolution and loss of the rock strength were observed at the inlet side of the core as a result of the high pressure and temperature and the long contact time needed due to the slow dissolution rate of dolomite. Face dissolution is unwanted, as it consumes the treatment solution without improving the permeability and can cause operational problems for future treatments.

Experiments 2-6: Static Treatments

(127) Table 1 shows the result of the static treatments and compares treatments with 1 continuous soaking period (Experiments 2-4) and experiments with various subsequent soaking treatments divided by a wash (Experiments 5-6). In contrast to the dynamic treatment, face dissolution was negligible for all static treatments. Comparing the values obtained for every type of test it is possible to observe a different tendency. While the continuous soaking time has a clear tendency to achieve a maximum increase in permeability of around 35%, the repeated soak-wash treatments show a linear increase, since with every injection fresh GLDA will react with the dolomite. In particular, the repeated soak-wash treatments indicate that cores consisting of material with a low dissolution rate in the treatment solution can be successfully stimulated, without the need for high pressures or long injection times, reducing the risk of face dissolution.

(128) TABLE-US-00002 TABLE 1 Coreflood experiments on dolomite cores with continuous soaking and repeated soak-wash treatments Initial Final Soaking Permeability Permeability K.sub.f/K.sub.i (% of Experiment Time K.sub.i (mD) K.sub.f (mD) increase) 2 1 Hour 24.56 28.07 14.29 3 3 Hours 24.56 32.75 33.33 4 6 Hours 26.20 35.73 36.33 5 2 × 1 Hour 26.20 32.75 25.00 6 3 × 1 Hour 24.56 35.73 45.45