Method of acid stimulation or scale remediation

Abstract

A method includes: injecting into a downhole environment an aqueous treatment fluid containing (1) a mixture of at least three carboxylic acids, each of the at least three carboxylic acids being a monocarboxylic acid, a dicarboxylic acid, or a tricarboxylic acid, and (2) a chelate; and contacting the aqueous treatment fluid with at least one of a sandstone formation, a carbonate formation, or a carbonate scale.

Description

METHOD OF ACID STIMULATION OR SCALE REMEDIATIONCROSS REFERENCE TO RELATED APPLICATIONSThis application claims the benefit of U.S. Application No. 18 / 672760, filed on May 23, 2024, which is incorporated herein by reference in its entirety.BACKGROUND

[0001] Hydrocarbons sometimes exist in a formation but cannot flow readily into a well because the formation has very low permeability. Acidizing wells is a process for increasing or restoring the permeability of the formation so as to facilitate the flow of oil and gas from the formation into the well. This process involves treating the formation with an acid to dissolve fines, scales, or other materials that may plug or clog the pores, thereby opening the pores and creating flow channels to enhance the permeability of the formation.

[0002] Acidizing fluids, such as hydrochloric acid or a mixture of hydrofluoric and hydrochloric acids, have been used in formation acidizing operations. While such fluids have high acid strength and can react quickly with fines and scales, they have a tendency to corrode tubing, casing and downhole equipment, such as gravel pack screens and downhole pumps, especially at elevated temperatures. Accordingly, there is a continuing need for improved method to enhance the permeability of formations.SUMMARY

[0003] A method includes: injecting into a downhole environment an aqueous treatment fluid comprising (1) a mixture of at least three carboxylic acids, each of the at least three carboxylic acids being a monocarboxylic acid, a dicarboxylic acid, or a tricarboxylic acid, and (2) a chelate; and contacting the aqueous treatment fluid with at least one of a sandstone formation, a carbonate formation, or a carbonate scale in the downhole environment.BRIEF DESCRIPTION OF THE DRAWINGS

[0004] The following descriptions should not be considered limiting in any way.With reference to the accompanying drawings, like elements are numbered alike:

[0005] FIG. 1 is a picture of glass jars containing a control without a chelate or Solutions 1-3 with different chelates after storage at 180°F for 10 minutes;

[0006] FIG. 2A is a picture of a glass jar containing a control without a chelate afterstorage at 180°F for 2 hours, and FIG. 2B is a picture of a glass jar containing Solution 7 having 20 wt% of HEDTA after storage at 180°F for 22 hours after cooling;

[0007] FIG. 3 A is a picture of a glass jar containing a control without a chelate after storage at 180°F for 20 hours; FIG. 3B is a picture of a glass jar containing Solution 8 with EDTA after storage at 180°F for 20 hours; and FIG. 3C is a picture of a glass jar containing Solution 9 containing EDTA and additives after storage at 180°F for 1 hour;

[0008] FIG. 4 is a graph of metal ion concentration (ppm) in the effluent as a function of time (hour) after a mineral composition is treated with Solution 10 containing EDTA for Example 4;

[0009] FIG. 5 is a graph of regain permeability after a mineral composition is treated with a brine pre-flush and Solution 11 containing EDTA for Example 5;

[0010] FIG. 6 is a graph of metal ion concentration (ppm) as a function of pore volume throughput after a mineral composition is treated with a brine pre-flush and Solution11 containing EDTA for Example 5;

[0011] FIG. 7 is a graph of regain permeability after a mineral composition is treated with an acid pre-flush and Solution 12 containing EDTA for Example 6;

[0012] FIG. 8 is a graph of metal ion concentration (ppm) as a function of pore volume throughput after a mineral composition is treated with an acid pre-flush and Solution12 containing EDTA for Example 6; and

[0013] FIG. 9 is a graph of effluent pH as a function of pore volume throughput after a mineral composition is treated with an acid pre-flush and Solution 12 containing EDTA for Example 6.DETAILED DESCRIPTION

[0014] It has been found that an aqueous treatment fluid comprising a mixture of at least three carboxylic acids, a chelate, optionally a hydrofluoric acid precursor, and optionally boric acid can be used in sandstone or carbonate formation acidizing or carbonate scale mitigation applications.

[0015] In an aspect, the aqueous treatment fluid can effectively dissolve calcium carbonate. Hydrofluoric acid precursor and boric acid are not required, and the treatment fluid can enhance the permeability of carbonate formation, or remove carbonate scales, or a combination thereof.

[0016] In another aspect, the aqueous treatment fluid can enhance the permeability of sandstone formations. For such an application, the treatment fluid comprises a hydrofluoricacid precursor, and boric acid in additional to a mixture of at least three carboxylic acids, and ethylenediaminetetraacetic acid or a derivative thereof.

[0017] Siliceous particles such as clays, feldspars and quartz in sandstone formation can restrict the flow of hydrocarbons and reduce the permeability of the formation. Since the siliceous particles react with fluoride ions forming soluble products, hydrofluoric acid or its precursor can be used together with other carboxylic acids instead of hydrochloride acid in sandstone matrix acidizing. An example of such an acid composition comprises a mixture of at least three carboxylic acids, boric acid, and hydrofluoric acid precursor. However, precipitates may form during an acidizing treatment using such an acid composition. The precipitates may include low solubility fluoride salts such as calcium fluoride. The formation of the low solubility fluoride salts can decrease the concentration of free fluoride ions thus reducing its availability for reaction with siliceous particles. The formation of precipitates can also potentially reduce the permeability of the formation.

[0018] It has been found that adding a chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof) to an acid composition containing a mixture of at least three carboxylic acids, boric acid, and a hydrofluoric acid precursor can provide an aqueous treatment fluid with improved solubility when used in sandstone matrix acidizing. In particular, the aqueous treatment fluid can maintain the concentration of free fluoride ions for improved HF generation and reaction with sandstone formation, clay and silica fines. The chelates may be further helping in stimulation by interacting with the aluminosilicates from the formation.

[0019] In as aspect, provided is an aqueous treatment fluid comprising a mixture of at least three carboxylic acids, a chelate, optionally a hydrofluoric acid precursor, and optionally boric acid.

[0020] Examples of the carboxylic acids include monocarboxylic acids such as formic acid, acetic acid, propionic acid, butyric acid, valeric acid, caproic acid, enanthic acid, caprylic aid, pelargonic acid, capric acid, undecylic acid, lauric acid, tridecylic acid, myristic acid, pentadecanoic acid, palmitic acid, margaric acid, steric acid, arachidic acid, or a combination thereof; dicarboxylic acids such as oxalic acid, malonic acid, succinic acid, glutaric acid, adipic acid, pimelic acid, suberic acid, azelaic acid, sebacic acid, or a combination thereof; and tricarboxylic acids such as citric acid, isocitric acid, aconitic acid, propane- 1, 2, 3 -tricarboxylic acid, trimesic acid, or combinations thereof.

[0021] A particularly useful mixture of the at least three carboxylic acids contains at least one water-soluble dicarboxylic acid having a relatively low molecular weight, that is, has a formula weight of 175 or less. Suitable dicarboxylic acids include oxalic acid(ethanedioic acid), malonic acid (propanedioic acid), succinic acid (butanedioic acid), glutaric acid (pentanedioic acid), adipic acid (hexanedioic acid), pimelic acid (heptanedioic acid), or a combination thereof. As a specific example, the dicarboxylic acids in the mixture include succinic acid, glutaric acid, adipic acid, or a combination thereof. The mixture can comprise about 40 to about 70 wt % of glutaric acid, about 10 to about 40 wt % of succinic acid, and 0 to 30 wt% or 1 to 30 wt% of adipic acid, each based on a total weight of the mixture. Preferably, the mixture comprises about 40 to about 70 wt % of glutaric acid, about 10 to about 30 wt % of succinic acid, and about 10 to about 30 wt % of adipic acid, each based on a total weight of the mixture. The mixture of at least three carboxylic acids can be present in the aqueous treatment fluid in an amount of about 1 to about 20 wt%, about 2 to about 15 wt%, preferably about 4 to about 12 wt%, more preferably about 2 to about 10 wt%, each based on a total weight of the aqueous treatment fluid.

[0022] For sandstone acidizing, a hydrofluoric acid precursor is used together with the mixture of at least three carboxylic acids. Hydrofluoric acid is used to aid in dissolving silicates. Preferably, a hydrofluoric acid precursor that hydrolyzes to hydrofluoric acid may be used. Examples of the hydrofluoric acid precursor include ammonium bifluoride (ABF), ammonium fluoride (AF), alkali metal fluorides and bifluorides (where the alkali metal is sodium, potassium or the like) as well as transition metal fluorides (for instance hexafluorotitanate salts and the like) or a combination thereof. The hydrofluoric acid precursor can be present in the aqueous treatment fluid in an amount of about 0. 1 to about 5 wt%, about 0.5 to about 4 wt%, about 1 to about 4 wt%, or about 1 to 3 wt%, each based on a total weight of the aqueous treatment fluid.

[0023] Boric acid can be used to delay the release of the hydrofluoric acid from the hydrofluoric acid precursor so that the hydrofluoric acid release is retarded and the acids in the treatment fluid may be injected further or deeper into the sandstone formation before the hydrofluoric acid is released. In an aspect, the weight ratio of the hydrofluoric acid precursor to boric acid is about 0.1 to about 5, or about 1.5 to about 3, or about 2.

[0024] The chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof) in the aqueous treatment fluid can increase the solubility of the sandstone formation. Without the chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof), fluoride ions can form precipitates thus reducing its availability for reaction with sandstone formation, clay and silica fines. With the chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof), the solubility of the aqueous treatment fluid is increased, and the concentration of free fluoride ions is maintained thus preserving its availability to enhance permeability ofsandstone formations. In addition, it is discovered that the chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof) does not interfere with the generation of hydrofluoric acid. Furthermore, the chelate (ethylenediaminetetraacetic acid or a derivative thereof) is compatible with additives that are commonly used in acidizing formulations. The chelate (e.g. ethylenediaminetetraacetic acid or a derivative thereof) can also facilitate the dissolution of calcium carbonate. 0025 J The chelate can include, for example, ethylenediaminetetraacetic acid or a derivative thereof, glutamic acid diacetic acid or a derivative thereof, and / or N-(2- hydroxyethyl)ethylenediaminetriacetic acid or a derivative thereof. As used herein, a derivative thereof can include a salt thereof. Accordingly, a derivative of ethylenediaminetetraacetic acid can include a salt of ethylenediaminetetraacetic acid. Suitable salts include alkali metal salts such as EDTA disodium salt, ammonium salts, sodium calcium salts, tetrasodium salts, di-ammonium salts, and tetra-ammonium salts. The content of the chelate in the aqueous treatment fluid can be about 1 to about 80 wt%, about 2.5 to about 60 wt%, about 5 to about 50 wt%, preferably about 5 to about 40 wt%, about 5 to about 30 wt%, or about 10 to about 30 wt%, and more preferably about 15 to about 25 wt%, based on a total weight of the aqueous treatment fluid.

[0026] The aqueous treatment fluid contains water or a brine. The content of the water or brine can be about 10 to about 80 wt%, about 20 to about 70 wt%, about 30 to about 60 wt%, or about 40 to about 50 wt%, based on a total weight of the aqueous treatment fluid,

[0027] The aqueous treatment fluid may optionally contain other additives such as iron control agents, clay control agents, non-emulsifiers, friction reducers, H2S scavengers, corrosion inhibitors, corrosion inhibitor intensifiers, anti-sludge agents, biocides, organic solvents, and / or foaming agents. The content of the other additives can range from about 0.1 to about 10 wt%, from about 0.5 to about 10 wt%, from about 1 to about 10 wt%, or from about 2 to about 8 wt%, based on a total weight of the aqueous treatment fluid.

[0028] The aqueous treatment fluid can also be free of inorganic acids or organic acids that are not specifically mentioned in this disclosure. For example, the aqueous treatment fluid can be free of inorganic acids (such as HC1) other than boric acid and HF. And the aqueous treatment fluids can be free of organic acids other than succinic acid, glutaric acid, adipic acid, and ethylenediaminetetraacetic acid or a derivative thereof.

[0029] The pH of the aqueous treatment fluid can range from about 2 to about 7, from about 2 to about 6, or from about 2 to about 5. The aqueous treatment fluid can be less corrosive than fluids containing hydrochloric acid, or inorganic / organic acids not specificallymentioned in the disclosure.

[0030] The aqueous treatment fluid can be used to enhance the permeability of sandstone or carbonate formations. The aqueous treatment fluid can also be used to mitigate carbonate scale deposited on the formation, for example a near wellbore area, a downhole equipment, or a combination thereof. The carbonate formation and the carbonate scale can include calcium carbonate.[0031 J In an aspect, a method comprises injecting the aqueous treatment fluid into a downhole environment; and contacting the aqueous treatment fluid with at least one of a sandstone formation, a carbonate formation, or a carbonate scale to enhance the permeability of the sandstone / carbonate formation, to remove the carbonate scale, or a combination thereof.

[0032] As a specific example, a method of treating a sandstone formation comprises injecting into the sandstone formation an aqueous treatment fluid comprising, or consisting of, based on a total weight of the aqueous treatment fluid: about 2 to about 15 wt%, about 4 to 12 wt%, or about 4 to 8 wt% of a mixture of glutaric acid, succinic acid, and adipic acid, about 0.1 to about 5 wt%, about 0.5 to about 4 wt%, about 1 to about 4 wt%, or about 1 to about 3 wt% of a hydrofluoric precursor such as ammonium bifluoride, ammonium fluoride, or a combination thereof, boric acid, where a weight ratio of the hydrofluoric precursor to the boric acid is about 0.1 to about 5, about 1.5 to about 3, or about 2; about 2.5 to about 40 wt%, about 5 to about 30 wt%, about 10 to about 30 wt%, or about 15 to about 25 wt% of ethylenediaminetetraacetic acid or a salt thereof, water or a brine, and optionally about 1 wt% to about 10 wt% of an additive comprising or consisting of an iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosion inhibitor intensifier, an anti-sludge agent, a biocide, an organic solvent, or a foaming agent, or a combination thereof, the aqueous treatment fluid having a pH of about 2 to about 7, and contacting the sandstone formation with the aqueous treatment fluid to enhance the permeability of the sandstone formation.

[0033] As another specific example, a method of removing calcium carbonate from a downhole environment comprises injecting into the downhole treatment fluid an aqueous treatment fluid comprising, or consisting of, based on a total weight of the aqueous treatment fluid: about 2 to about 15 wt% of a mixture of glutaric acid, succinic acid, and adipic acid; and about 2.5 to about 40 wt%, about 0.5 or 5 to about 30 wt%, about 10 to about 30 wt%, or about 15 to about 25 wt% of ethylenediaminetetraacetic acid or a salt thereof, water or a brine, and optionally about 1 wt% to about 10 wt% of an additive comprising or consisting ofan iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosion inhibitor intensifier, an anti-sludge agent, a biocide, an organic solvent, or a foaming agent, or a combination thereof, the aqueous treatment fluid having a pH of about 2 to about 7, and contacting calcium carbonate in the downhole environment with the aqueous treatment fluid to dissolve the calcium carbonate in the downhole environment. 0034 J The aqueous treatment fluid can be injected into the downhole environment through metal equipment. Due to the less corrosive nature of the aqueous treatment fluid, the corrosion rate of the metal equipment is less than other inorganic or organic acids or mixtures thereof for coiled tubing and other grade of metal equipment.

[0035] For stimulation treatments, contact times are determined from the maximum pumping rate that does not cause the downhole pressure to exceed the fracturing pressure. This type of treatment is called a “matrix” acid job. The contact times can vary but usually range from about 0.5 hour to about 24 hours. The aqueous treatment fluid can contact the sandstone or carbonate formation at a temperature of greater than 60°F and lower than 500°F.

[0036] Before the aqueous treatment fluid is injected, the sandstone or carbonate formation or carbonate scale can be treated with a pre -flush fluid. The pre-flush fluid can include a brine pre-flush fluid or an acid pre-flush fluid. The brine pre-flush fluid can include ammonium chloride. The acid pre-flush fluid can include a mixture of at least three carboxylic acids as discussed in the context of the aqueous treatment fluid. As compared with the aqueous treatment fluid, the acid pre-flush fluid does not include the hydrofluoric acid precursor or boric acid. Ethylenediaminetetraacetic acid or a derivative thereof is optional and preferably not included in the acid pre-flush fluid.

[0037] The methods and the aqueous treatment fluids are further illustrated in the following examples. It is noted that the components of the fluids and the amounts thereof are not limited to the specific examples. EXAMPLES

[0038] Materials used in the examples are shown in Table 1.Table 1Example 1

[0039] A control sample was prepared by combining Acid 1 (10 wt%), ABF (1.5 wt%), boric acid (1 wt%), and water. Solutions 1-3 were prepared by adding a chelate (FERROTROL 35OL, HEDTA, or GLDA respectively) to the control sample. Each of the control and Solutions 1-3 was independently poured into a glass jar. Then the glass jars with the control and Solutions 1-3 were kept at 180°F for 10 minutes. Since HF reacts with glass, it is preferable that there is no precipitation. As shown in FIG. 1, Solution 2 containing HEDTA as the chelate provided the best results with no or minimal precipitation as compared to the control and Solutions 1, and 3 after storage at 180°F for 10 minutes. Example 2

[0040] Solutions 4-7 were prepared by adding FERROTROL 350L, GLDA, 15 wt% HEDTA, or 20 wt% of HEDTA to the control sample of Example 1. To prepare Solution 7, heat had to be applied in order to dissolve HEDTA. Each of the control and Solutions 4-7 was independently poured into a glass jar. Then the glass jars with the control and Solutions 4-7 were kept at 180oF. The amount of time in minutes for precipitate to form is summarized in Table 2.Table 2.

[0041] A picture of the control after 2 hours at 180°F is shown in FIG. 2A, indicating the formation of precipitate. A picture of Solution 7 after storage at 180°F for 22 hours is shown in FIG. 2B. Although little precipitate was observed after 22 hours storage at 180°F,upon cooling, HEDTA redeposited in the solution as crystals, possibly due to the saturation of the chelate. In other words, 15 wt% of HEDTA was insufficient to prevent the formation of precipitate at 180°F. While 20 wt% of HEDTA is good at preventing the formation of precipitate at 180°F, HEDTA forms crystals upon cooling, which is not desired.Example 3

[0042] Solution 8 was prepared by adding EDTA (18 wt%) to the control sample of Example 1. Each of the control and Solution 8 was independently poured into a glass jar. Then the glass jars with the control and Solution 8 were kept at 180°F for 20 hours. As shown in FIG. 3A (control) and FIG. 3B (Solution 8), precipitate was observed for the control while there was no precipitate for Solution 10 when EDTA was added.

[0043] Solution 9 was prepared by adding EDTA (18 wt%), and additives (a clay control agent, an iron control agent, a non-emulsifier, and a friction reducer, collectively, 5.3 wt%) to the control sample of Example 1. Solution 9 had a pH of 4.94, and was poured into a glass jar. As shown in FIG. 3C, there was no precipitate after 1 hour at 180°F. The results indicate that EDTA containing acid solution is compatible with additives that may be used in a stimulation fluid.Example 4

[0044] A mineral composition was exposed to Solution 10 containing Acid 1 (5 wt%), ABF (1.5 wt%), boric acid, EDTA (18 wt%), additives (5.3 wt%, clay control agent, iron control agent, non-emulsifier, and friction reducer), and water for 30 minutes, 1 hour, 2 hours, 3 hours, or 4 hours. Effluents were collected and evaluated by Inductively Coupled Plasma spectroscopy (ICP) for the concentrations of Al, Ca, Fe, Mg, and Si. The results are summarized in Table 3 and FIG. 4. The results indicate that metals such as Al, Ca, Fe, Mg, and Si can be effectively removed from the mineral composition, and Solution 10 has good stimulation performance.Table 3.Example 5

[0045] A mineral composition was treated with a brine pre-flush (5 wt% ammonium chloride), then Solution 11 containing Acid 1 (5 wt%), ABF (2.5 wt%), boric acid, EDTA (18 wt%), additives (5.3 wt%, clay control agent, iron control agent, non-emulsifier, and friction reducer), and water. A graph of regain permeability after acid stimulation is shown in FIG. 5. The ICP results are shown in FIG. 6, which is a graph of the concentrations of Al, Ca, K, Mg, Na, and Si in the effluent as a function of pore volume throughput. The results indicate that metals such as Al, Ca, Fe, Mg, and Si can be effectively removed from the mineral composition, and Solution 11 has good stimulation performance. Example 6

[0046] A mineral composition was treated with an acid pre-flush (a pre-acid containing Acid 1), then Solution 12 also referred to as a “Main Acid” containing Acid 1 (5 wt%), ABF (2.5 wt%), EDTA (18 wt%), additives (5.3 wt%, clay control agent, iron control agent, non-emulsifier, and friction reducer), and water. A graph of regain permeability after acid pre-flush and main acid treatment (stimulation) is shown in FIG. 7. The ICP results are shown in FIG. 8, which is a graph of the concentrations of Al, Ca, K, Mg, Na, and Si in the effluent as a function of pore volume throughput. The results show that Solution 12 is effective in removing metals and has good stimulation performance. The effluent pH was measured and shown in FIG. 9 as a function of pore volume throughput. The pH result shows moderate to neutral pH. As compared to acids with lower pH values, the treatment fluids as disclosed herein can have lower corrosion to downhole tools and mitigate health, safe, and environment (HSE) risks.Example 7

[0047] One hundred (100) mL of a solution of Acid 1 (5 wt%) with 18 wt% chelate was added to one gram of calcium carbonate and put to react at 180°F. After 1 hour of reaction time, 38% of the calcium carbonate was dissolved.

[0048] Set forth below are various aspects of the disclosure.

[0049] Aspect 1. A method comprising: injecting into a downhole environment an aqueous treatment fluid comprising ( 1 ) a mixture of at least three carboxylic acids, each of the at least three carboxylic acids being a monocarboxylic acid, a dicarboxylic acid, or a tricarboxylic acid, and (2) a chelate such as ethylenediaminetetraacetic acid or a derivative thereof, and contacting the aqueous treatment fluid with at least one of a sandstone formation, a carbonate formation, or a carbonate scale in the downhole environment.

[0050] Aspect 2. The method of Aspect 1, wherein the carbonate formation and thecarbonate scale comprise calcium carbonate, and the method comprises contacting the calcium carbonate with the aqueous treatment fluid to dissolve the calcium carbonate.

[0051] Aspect 3. The method of Aspect 1, wherein the aqueous treatment fluid further comprises a hydrofluoric acid precursor and boric acid, and the method comprises contacting the sandstone formation with the aqueous treatment fluid to enhance the permeability of the sandstone formation.

[0052] Aspect 4. The method of any one of Aspects 1 to 3, wherein the aqueous treatment fluid has a pH of about 2 to about 7.

[0053] Aspect 5. The method of any one of Aspects 1 to 3, wherein the mixture of the at least three carboxylic acids comprises the dicarboxylic acid, and the dicarboxylic acid comprises at least one of succinic acid, glutaric acid, or adipic acid.

[0054] Aspect 6. The method of any one of Aspects 1 to 5, wherein the mixture of the at least three carboxylic acids comprises: about 40 to about 70 wt% of glutaric acid, about 10 to about 40 wt% of succinic acid, and about 0 to about 30 wt% of adipic acid, each based on a total weight of the mixture of the at least three carboxylic acids.

[0055] Aspect 7. The method of any one of Aspects 1 to 6, wherein a content of the mixture of the three carboxylic acids in the aqueous treatment fluid is about 1 to about 20 wt% based on a total weight of the aqueous treatment fluid.

[0056] Aspect 8. The method of any one of Aspects 3 to 7, wherein the hydrofluoric acid precursor is ammonium bifluoride, ammonium fluoride, or a combination thereof.

[0057] Aspect 9. The method of any one of Aspects 3 to 8, wherein a content of the hydrofluoric acid precursor in the aqueous treatment fluid is about 0.1 to about 5 wt% based on a total weight of the aqueous treatment fluid.

[0058] Aspect 10. The method of any one of Aspects 3 to 9, wherein a weight ratio of the hydrofluoric acid precursor to the boric acid is about 0.1 to about 5.

[0059] Aspect 11. The method of any one of Aspects 1 to 10, wherein the aqueous treatment fluid comprises the derivative of ethylenediaminetetraacetic acid, and the derivative of ethylenediaminetetraacetic acid is a salt of ethylenediaminetetraacetic acid.

[0060] Aspect 12. The method of any one of Aspects 1 to 10, wherein a content of the chelate in the aqueous treatment fluid is about 1 wt.% to about 80 wt.% based on a total weight of the aqueous treatment fluid.

[0061] Aspect 13. The method of any one of Aspects 1 to 12, wherein the aqueous treatment fluid further comprises at least one of an iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosioninhibitor intensifier, an anti- sludge agent, a biocide, an organic solvent, or a foaming agent.

[0062] Aspect 14. The method of any one of Aspects 1 to 13, wherein the aqueous treatment fluid is free of hydrochloric acid.

[0063] Aspect 15. The method of any one of Aspects 1 to 14, wherein the contacting is conducted at a temperature greater than 250°F.

[0064] Aspect 16. The method any one of Aspects 1 to 15, further comprising injecting into the downhole environment a pre- flush fluid which is a brine.

[0065] Aspect 17. The method of any one of Aspects 1 to 16, further comprising injecting into the downhole environment a pre- flush fluid which comprises the mixture of the at least three carboxylic acids.

[0066] Aspect 18. A method of treating a sandstone formation, the method comprising: injecting into the sandstone formation an aqueous treatment fluid comprising, based on a total weight of the aqueous treatment fluid: about 1 to about 15 wt% of a mixture of glutaric acid, succinic acid, and adipic acid, about 0.1 to about 5 wt% of a hydrofluoric precursor, which comprises ammonium bifluoride, boric acid, where a weight ratio of the ammonium bifluoride to the boric acid is about 0. 1 to about 5; and about 5 to about 30 wt% of ethylenediaminetetraacetic acid or a salt thereof, the aqueous treatment fluid having a pH of about 2 to about 7, and contacting the sandstone formation with the aqueous treatment fluid to enhance the permeability of the sandstone formation.

[0067] Aspect 19. The method of Aspect 18, wherein the aqueous treatment fluid further comprises at least one of an iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosion inhibitor intensifier, an anti-sludge agent, a biocide, an organic solvent, or a foaming agent.

[0068] Aspect 20. The method of Aspect 18 or 19, further comprising injecting into the sandstone formation a pre-flush fluid which is a brine.

[0069] Aspect 21. The method of any one of Aspects 18 to 20, further comprising injecting into the sandstone formation a pre-flush fluid which comprises the mixture of the at least three carboxylic acids.

[0070] Aspect 22. A method of removing calcium carbonate from a downhole environment, the method comprising: injecting into the downhole environment an aqueous treatment fluid comprising, based on a total weight of the aqueous treatment fluid: about 1 to about 20 wt% of a mixture of glutaric acid, succinic acid, and adipic acid; and about 0.5 to about 30 wt% of ethylenediaminetetraacetic acid or a salt thereof, the aqueous treatment fluid having a pH of about 2 to about 7, and contacting the calcium carbonate in the downholeenvironment with the aqueous treatment fluid to dissolve the calcium carbonate in the downhole environment

[0071] All ranges disclosed herein are inclusive of the endpoints, and the endpoints are independently combinable with each other. As used herein, “combination” is inclusive of blends, mixtures, alloys, reaction products, and the like. All references are incorporated herein by reference.

[0072] The use of the terms “a” and “an” and “the” and similar referents in the context of describing the invention (especially in the context of the following claims) are to be construed to cover both the singular and the plural, unless otherwise indicated herein or clearly contradicted by context. The modifier “about” used in connection with a quantity is inclusive of the stated value and has the meaning dictated by the context (e.g., it includes the degree of error associated with measurement of the particular quantity). In an embodiment, the term “about” means that the value associated with about can vary by 10%. Regarding various ranges, it is understood that any lower threshold may be used with any upper threshold to give a suitable alternative range. Unless defined otherwise, technical and scientific terms used herein have the same meaning as is commonly understood by one of skill in the art to which this invention belongs.

[0073] All references cited herein are incorporated by reference in their entirety. While typical embodiments have been set forth for the purpose of illustration, the foregoing descriptions should not be deemed to be a limitation on the scope herein. Accordingly, various modifications, adaptations, and alternatives can occur to one skilled in the art without departing from the spirit and scope herein.

Claims

CLAIMSWhat is claimed is:

1. A method characterized by: injecting into a downhole environment an aqueous treatment fluid comprising a mixture of at least three carboxylic acids, each of the at least three carboxylic acids being a monocarboxylic acid, a dicarboxylic acid, or a tricarboxylic acid, and a chelate; and contacting the treatment fluid with at least one of a sandstone formation, a carbonate formation, or a carbonate scale,2. The method of claim 1 , wherein the aqueous treatment fluid further comprises a hydrofluoric acid precursor, boric acid, and the method comprises contacting the sandstone formation with the treatment fluid to enhance the permeability of the sandstone formation.

3. The method of claim 1, wherein the carbonate formation and the carbonate scale comprise calcium carbonate; the method comprises contacting the calcium carbonate in the carbonate formation or the carbonate scale, or a combination thereof with the aqueous treatment fluid to dissolve the calcium carbonate.

4. The method of claim 1 , wherein the mixture of the at least three carboxylic acids comprises the dicarboxylic acid, and the dicarboxylic acid comprises at least one of succinic acid, glutaric acid, or adipic acid.

5. The method of claim 1, wherein the mixture of the at least three carboxylic acids comprises: about 40 to about 70 wt% of glutaric acid, about 10 to about 40 wt% of succinic acid, and about 0 to about 30 wt% of adipic acid, each based on a total weight of the mixture of the at least three carboxylic acids.

6. The method of claim 1 , wherein a content of the mixture of the three carboxylic acids in the aqueous treatment fluid is about 1 to about 20 wt% based on a total weight of the aqueous treatment fluid.

7. The method of claim 2, wherein the hydrofluoric acid precursor is ammonium bifluoride, ammonium fluoride, or a combination thereof.

8. The method of claim 2, wherein a content of the hydrofluoric acid precursor in the aqueous treatment fluid is about 0.1 to about 5 wt% based on a total weight of the aqueous treatment fluid, and a weight ratio of the hydrofluoric acid precursor to the boric acid is about 0.1 to about 5.

9. The method of any one of claims 1 to 9, wherein the chelate comprises ethylenediaminetetraacetic acid or a derivative thereof.

10. The method of any one of claims 1 to 9, wherein the chelate comprises the derivative of ethylenediaminetetraacetic acid, and the derivative of ethylenediaminetetraacetic acid is a salt of ethylenediaminetetraacetic acid.

11. The method of any one of claims 1 to 9, wherein a content of the chelate in the aqueous treatment fluid is about 1 wt.% to about 80 wt.% based on a total weight of the aqueous treatment fluid.

12. The method of any one of claims 1 to 9, wherein the aqueous treatment fluid further comprises at least one of an iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosion inhibitor intensifier, an anti-sludge agent, a biocide, an organic solvent, or a foaming agent.

13. The method of an one of claims 1 to 9, further characterized by injecting into the downhole environment a pre-flush fluid, wherein the pre- flush fluid is a brine or the preflush fluid comprises the mixture of the at least three carboxylic acids.

14. The method of claim 1, the method comprising: injecting the sandstone formation an aqueous treatment fluid comprising, based on a total weight of the aqueous treatment fluid: about 1 to about 15 wt% of a mixture of glutaric acid, succinic acid, and adipic acid, about 0.1 to about 5 wt% of a hydrofluoric precursor, which comprises ammonium bifluoride, boric acid, where a weight ratio of the ammonium bifluoride to the boric acid is about 0.1 to about 5; and about 5 to about 30 wt% of ethylenediaminetetraacetic acid or a salt thereof, and optionally at least one of an iron control agent, a clay control agent, a non-emulsifier, a friction reducer, a H2S scavenger, a corrosion inhibitor, a corrosion inhibitor intensifier, an anti-sludge agent, a biocide, an organic solvent, or a foaming agent, the aqueous treatment fluid having a pH of about 2 to about 7, andcontacting the sandstone formation with the aqueous treatment fluid to enhance the permeability of the sandstone formation.

15. The method of claim 1, the method comprising: injecting into the downhole environment an aqueous treatment fluid comprising, based on a total weight of the aqueous treatment fluid: about 1 to about 20 wt% of a mixture of glutaric acid, succinic acid, and adipic acid; and about 0.5 to about 30 wt% of ethylenediaminetetraacetic acid or a salt thereof, the aqueous treatment fluid having a pH of about 2 to about 7, and contacting the calcium carbonate in the downhole environment with the aqueous treatment fluid to dissolve the calcium carbonate in the downhole environment.

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