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Title:
ACIDIZING TREATMENT FLUID FOR DELAYED ACIDIFICATION IN THE OIL FIELD INDUSTRY
Document Type and Number:
WIPO Patent Application WO/2021/233781
Kind Code:
A1
Abstract:
The disclosure is directed to a process for treating a subterranean earth formation by introducing an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid into said subterranean earth formation in the presence of at least one scaling inhibitor comprising specific polymers of maleic acid and/or acrylic acid. It also pertains to an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid, a scaling inhibitor and optionally a chelating agent.

Inventors:
O BOEN, Ho (Zutphenseweg 10, 7418 AJ Deventer, NL)
BOKKERS, Albert (Zutphenseweg 10, 7418 AJ Deventer, NL)
VAN LARE, Cornelis, Elizabeth, Johannus (Zutphenseweg 10, 7418 AJ Deventer, NL)
KOOIJMAN, Cornelis (Zutphenseweg 10, 7418 AJ Deventer, NL)
LEON MATHEUS, Maria, Antonieta (7214 GC Epse, NL)
Application Number:
PCT/EP2021/062830
Publication Date:
November 25, 2021
Filing Date:
May 14, 2021
Export Citation:
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Assignee:
NOURYON CHEMICALS INTERNATIONAL B.V. (6824BM Arnhem, NL)
International Classes:
C09K8/72; E21B43/27
Attorney, Agent or Firm:
FRASER, James (Cambridge House Henry Street, Bath BA11BT, GB)
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Claims:
CLAIMS

1 A process for treating a subterranean earth formation by introducing an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid into said subterranean earth formation in the presence of at least one scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards.

2 A process as claimed in claim 1 , wherein the at least one scaling inhibitor has a total number of carboxyl groups between 7 and 100, preferably between 10 and 90.

3. A process as claimed in claim 1 or claim 2, wherein the at least one scaling inhibitor is present in the acidizing treatment fluid that is introduced into the subterranean earth formation in an amount of from about 0.005 to about 7.5 wt%, based on the total weight of the acidizing treatment fluid.

4. A process as claimed in any preceding claim, wherein the monovalent salt of monochloroacetic acid is present in the acidizing treatment fluid that is introduced into the subterranean earth formation in an amount of from about 3 to about 20 wt%, based on the total weight of the acidizing treatment fluid.

5. A process as claimed in any preceding claim, wherein a chelating agent is also introduced into the subterranean earth formation. 6 A process as claimed in claim 5, wherein the chelating agent comprises at least one monovalent carboxylate salt group and furthermore comprises a carbon chain carrying at least five hydroxyl groups.

7. A process as claimed in claim 5 or claim 6, wherein the chelating agent comprises sodium gluconate.

8. A process as claimed in any of claims 5 to 7, wherein the chelating agent is present in the acidizing treatment fluid in an amount of from 0.01 to 30 wt% based on the total weight of the acidizing treatment fluid. 9. A process as claimed in any preceding claim, wherein the subterranean earth formation comprises carbonate-based rock.

10. An aqueous acidizing treatment fluid comprising

(i) a monovalent salt of monochloroacetic acid; (ii) at least one scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof; and (iii) optionally, a chelating agent, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards. 11. An aqueous acidizing treatment fluid as claimed in claim 10, wherein the at least one scaling inhibitor has a total number of carboxyl groups between 7 and 100, preferably between 10 and 90.

12. An aqueous acidizing treatment fluid as claimed in claim 10 or claim 11 , wherein the monovalent salt of monochloroacetic acid is present in an amount of from about 3 to about 20 wt%, based on the total weight of the acidizing treatment fluid, and the at least one scaling inhibitor is present in an amount of from about 0.005 to about 7.5 wt%, based on the total weight of the acidizing treatment fluid. 13. An aqueous acidizing treatment fluid as claimed in any of claims 10 to 12, wherein the chelating agent is present in the acidizing treatment fluid in an amount of from 0.01 to 30 wt%, based on the total weight of the acidizing treatment fluid.

14. An aqueous acidizing treatment fluid as claimed in claim 13, wherein the chelating agent comprises at least one monovalent carboxylate salt group and furthermore comprises a carbon chain carrying at least five hydroxyl groups, such as, sodium gluconate.

Description:
ACIDIZING TREATMENT FLUID FOR DELAYED ACIDIFICATION IN THE OIL FIELD

INDUSTRY

The present invention is directed to a process for treating a subterranean earth formation and an aqueous acidizing treatment fluid therefor.

Background

Acidification fluids are commonly used in the oil industry to create wormholes to connect the wellbore with the formation. Typically, 15-28% hydrochloric acid (HCI) has been used but it has a disadvantage related to its high reactivity with the calcium carbonate (CaCOs) present in the limestone reservoirs. The reactivity of the HCI is highly affected by the temperature in the reservoir. The higher the temperature, the faster the HCI reacts hence forming wormholes with unstable structures that then collapse and block the access to the formation. For the previous reasons the use of HCI alone (i.e. without additives) is less preferred, especially at higher temperatures. Another disadvantage is its high corrosivity. To this end several corrosion inhibitors have been proposed, but the known commercial corrosion inhibitors are expensive and their performance at higher temperatures leaves much to be desired. As a rule of thumb, up to 200 °F (93 °C) the treatment can be performed with HCI and a corrosion inhibitor, but above 200 °F (93°C) a corrosion inhibitor intensifier is also needed. Corrosion inhibitor intensifiers are costly. They can be up to 60% of the total costs of the treatment. Furthermore, stability of the additives becomes a problem.

There is a need to access deeper wells as many of the recently discovered reservoirs are categorized as High Pressure High Temperature (HPHT). In that sense, it is of interest to find an alternative option to the HCI, which is not as reactive when exposed to high temperatures and offers an acidification feature which can be released in a controlled fashion.

To this end, several patent publications were issued concerning delayed acidification using the hydrolyzation of chlorocarboxylic acid salts. During the hydrolyzation, glycolic acid is formed.

US 3,885,630 is directed to a method wherein acid-reactive material in or around a bore hole or well is acidized by contacting water-soluble weak acid and water-soluble weak acid salt, such as acetic acid and sodium acetate. US 4,122,896 is directed to a method wherein subterranean reservoirs are acidized by injecting a substantially acid-free aqueous solution of a chloro carboxylic acid salt, such as mono or di-chloro acetic acid salt or 2 chloro propionic acid salt, into the reservoir.

We have found however, that the glycolic acid formed reacts with the calcium carbonate being present in the limestone reservoirs forming calcium glycolate. Calcium glycolate has low solubility and precipitates easily. Precipitation of calcium glycolate during acidation in the oil wells (also referred to as scaling) is undesirable. The calcium glycolate may cause plugging in the confinements, such as the piping, if a sufficient amount of precipitate is formed. It has been further found that solutions with calcium glycolate in solution form a gel upon cooling to room temperature. This gel formation may cause plugging of the pipes as the acidification fluid is pumped back above ground level during extraction and/or while it is later stored.

Several patent publications have been issued describing scaling inhibitor compositions:

US 2009/0042748 relates to an acidizing fluid for sandstone formations which comprises an aqueous liquid, a fluoride source, and an effective amount of at least one homopolymer or copolymer of a polycarboxylic acid (e.g. polyacrylic acid). Said aqueous liquid may further comprise glycolic acid. It is mentioned that the polycarboxylic acid may include polymers formed from maleic acid.

WO 2009/016549 relates to a method for treating a subterranean formation which includes forming a treatment fluid including a carrier fluid, a solid acid-precursor, and a solid scale inhibitor. The solid acid-precursor includes a material that forms an acid at downhole conditions in the subterranean formation. The solid acid-precursor may be a homopolymer of glycolic acid or a copolymer of glycolic acid. The scale inhibitor is for instance a polyacrylate. The treatment fluid may furthermore comprise glycolic acid.

The method according to WO 2009/016549 includes performing an acid fracture treatment and inhibiting scale formation within the subterranean formation.

CN 105018061 relates to a composition for use in an oil well comprising a compound made including the following ingredients: 15-30 wt% methyl acrylate, 5-9 wt% 2-acrylamido-2- methylpropane sulfonic acid, 5-10 wt% sodium hydroxide, 10-20 wt% sodium chloroacetate, 3- 10 wt% ethylenediamine, 8-20 wt% sodium vinyl sulfonate, 30-50 wt% methanol and 14-20 wt% water.

GB 1258068 relates to a composition and process for inhibiting or removing alkaline earth salt scales in aqueous systems. Said composition may comprise from 1 to 500 parts by weight of glycolic acid and from 1 to 10 parts by weight of a water-soluble organic polymer such as polyacrylic acid.

We now have found a process for treating subterranean earth formation by means of injecting a delayed acidification fluid with a specific scaling inhibitor that provides good results with respect to both the delayed acidification and the scaling inhibition.

Summary of the Disclosure

The present disclosure is directed to a process for treating a subterranean earth formation by introducing an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid into said subterranean earth formation in the presence of at least one scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards.

The scaling inhibitor may be present in the acidizing treatment fluid that is introduced into the subterranean earth formation in an amount of from about 0.005 to about 7.5 wt% based on the total weight of the acidizing treatment fluid. However, it is also possible to introduce the scaling inhibitor into the subterranean earth formation prior to the introduction of an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid and no or less than 0.005 wt%, preferably less than 0.025 wt% of scaling inhibitor (based on the total weight of the acidizing treatment fluid).

The monovalent salt of monochloroacetic acid may be present in the acidizing treatment fluid that is introduced into the subterranean earth formation in an amount of from about 3 to about 20 wt%, based on the total weight of the acidizing treatment fluid. A chelating agent may be used in combination with the scaling inhibitor. A preferred chelating agent comprises at least one monovalent carboxylate salt group and furthermore comprises a carbon chain carrying at least five hydroxyl groups, such as, for example, sodium gluconate (see WO 2020/002011 A1). The chelating agent may be present in the acidizing treatment fluid that is introduced into the subterranean earth formation in an amount of between 0.01 and 30 wt%, based on the total weight of the acidizing treatment fluid. However, it is also possible to introduce the chelating agent into the subterranean earth formation prior to the introduction of an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid.

The present disclosure is further directed to an aqueous acidizing treatment fluid comprising

(i) a monovalent salt of monochloroacetic acid;

(ii) a scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof; and

(iii) optionally a chelating agent, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards.

Detailed description

As indicated above, the present disclosure is directed to a process for treating a subterranean earth formation by introducing an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid into said subterranean earth formation in the presence of at least one scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards.

In the present invention, a monovalent salt of monochloroacetic acid is used. "Monovalent salt of monochloroacetic acid" means that the cation in the monochloroacetate salt has a valency of one. The cation of the monovalent salt of monochloroacetic acid can be sodium, ammonium, lithium or potassium. Depending on the type of rock formation to be treated, the preferred cation of the salt can be chosen for the monochloroacetic acid salt. In the case of carbonate-based rock, the cation of the monochloroacetic acid salt is preferably sodium, potassium and/or lithium.

The cation of the salt of monochloroacetic acid is most preferably sodium (the sodium salt of monochloroacetic acid is hereinafter also denoted as SMCA).

The monovalent salt of monochloroacetic acid is preferably present in the acidizing treatment fluid in an amount of at least 3 wt%, preferably at least 5 wt% and most preferably at least 10 wt%, based on the total weight of the acidizing treatment fluid. The optimal amount of monovalent salt of monochloroacetic acid present in the acidizing treatment fluid ranges from about 3 to about 20 wt%, preferably from about 5 to about 18 wt%, more preferably from about 6 to about 16 wt%, and most preferably from about 8 to about 15 wt%, based on the total weight of the acidizing treatment fluid.

In addition to a monovalent salt of monochloroacetic acid, the acidizing treatment fluid may comprise glycolic acid. Preferably, the acidizing treatment fluid according to the present invention comprises a monovalent salt of monochloroacetic acid and less than 1 wt%, more preferably less than 0.1 wt% and most preferably no glycolic acid.

As explained above, a monovalent salt of monochloroacetic acid (MCA) can easily hydrolyze into glycolic acid (GA). The hydrolyzation rate depends on the temperature, concentration and pH. To assist with hydrolyzation, the pH of the acidizing treatment fluid is preferably above 7, more preferably above 8. In particular, the pH of the acidizing treatment fluid is preferably from 8 to 10 or from 8 to 9. Upon hydrolyzation of the monovalent salt of monochloroacetic acid into glycolic acid, the pH of the treatment fluid may be reduced to a value of from 3 to 6, preferably of from 4 to 6, and more preferably of from 5 to 6.

As also explained above, glycolic acid may react with calcium carbonate present in limestone reservoirs to form calcium glycolate. Calcium glycolate has low solubility (the maximum solubility of calcium glycolate is 1 .4 wt% at 25 °C and 3.04 wt% at 40°C) and precipitates easily. Precipitation of calcium glycolate during acidification in the oil wells (also referred to as scaling) is undesirable and can lead to plugging in the confinements, such as piping. In addition, it has been found that calcium glycolate in solution forms a gel upon cooling to room temperature, which can cause plugging as the acidification fluid is pumped back above ground level during extraction and/or while it is later stored. It has now been found that with the addition of a scaling inhibitor as described above, the precipitation of calcium glycolate is inhibited, so that scaling and plugging may be avoided. Further, with the process according to the disclosure, nicely formed wormholes are created, the stability of the earth formation is ensured, and the acidizing treatment fluid is effectively used.

The acidizing treatment fluid according to the present invention is preferably free of any fluoride source, such as hydrogen fluoride, hydrofluoric acid, ammonium fluoride and ammonium bifluoride.

As described above, the scaling inhibitor used in the present process comprises a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, or a salt thereof, having a total number of carboxyl groups between 5 and 200, preferably between 7 and 100, and more preferably between 10 and 90. The term “carboxyl” is used herein to refer to a carboxyl group in acid form (denoted as -COOH) or in neutral form (denoted as -COO X + ). The total number of carboxyl groups (or carboxylate salt groups) is calculated from the weight average molecular weight of the homopolymer/copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards (described further below).

The term “homopolymer” is used herein to refer to a polymer that is derived from one species of monomer, i.e., maleic acid or acrylic acid, but which may also contain one or more phosphonic or sulfonic functional groups. Likewise, the term “copolymer” is used herein to refer to a polymer derived from more than one species of monomer, i.e., maleic acid and acrylic acid, but which may also contain one or more phosphonic or sulfonic functional groups. When the homopolymer or copolymer contains phosphonic or sulfonic functional groups, these functional groups are preferably present in an amount of from 1 to 5 functional groups, preferably from 1 to 3 functional groups, and more preferably 1 or 2 functional groups per average homopolymer/copolymer chain. The scaling inhibitor may contain no phosphonic or sulfonic functional groups.

The presence (or absence) of phosphonic or sulfonic functional groups can be determined by 1 H, 13 C and 31 P-NMR analysis. For example, using a proton resonance frequency of 600 MHz, a carbon resonance frequency of 150 MHz and a phosphorous resonance frequency of 243 MHz. The sample spectrum can be quantified by calibration with a known molar concentration of NMR standard, and the number of phosphonic groups present per average homopolymer or copolymer chain can be calculated from the results. In the case of sulfonic groups, NMR alone will only provide a qualitative picture, i.e., the structure of the organic surround can be revealed. In order to quantify the number of sulfonic groups present per average homopolymer or copolymer, an additional technique, such as Inductive Couple Plasma techniques (e.g. ICP-MS), is required.

Suitable examples of such scaling inhibitors are the commercially available scale inhibitors Dequest P9000 (supplied by Italmatch Chemicals), Drewsperse 747A (supplied by Solenis), Belclene 200, Belclene 245, Belclene 283 and Belclene 499 (supplied by BWA Water Additives), Sokalan PA30, Sokalan 12S and Sokalan 20PN (supplied by BASF) and Acumer 1050 (supplied by Dow).

It has been found that the scaling inhibitor according the present disclosure gives an improved performance compared to other known scaling inhibiting compositions with respect to stability at both high (down-well) temperatures and upon cooling to room temperature, in combination with the delayed acidizing treatment fluid presently described. Without being bound by theory, it is believed that a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, or a salt thereof, having a total number of carboxyl groups between 5 and 200, is large enough and has enough carboxyl groups to effectively adhere to the calcium containing particles but not so large that entanglement occurs at lower temperatures.

As will be appreciated, for the scaling inhibitor to properly perform, the precipitate of the system, e.g., calcium glycolate, must be accessible to the scaling inhibitor. As such, it is preferred that the scaling inhibitor is fully miscible with the system in which precipitation is to be suppressed. If the scaling inhibitor is only partially miscible with the system, the amount of scaling inhibitor available to adhere to the scale particles may be reduced.

The scaling inhibitor may be present in the acidizing treatment fluid that is introduced, but it is also possible to introduce the scaling inhibitor prior to the introduction of an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid.

The amount of scaling inhibitor used may be kept relatively low so as to avoid cost increases and limit environmental burden. The amount of the scale inhibitor in the aqueous acidizing treatment fluid that is introduced into the subterranean earth formation lies preferably between about 0.005 and about 7.5 wt%, more preferably between about 0.05 and about 5 wt%, more preferably between about 0.2 and about 2 wt%, and most preferably between 0.4 and about 1 .5 wt%, based on the total weight of the acidizing treatment fluid. If the scale inhibitor is introduced separate from an acidizing treatment fluid comprising a monovalent salt of monochloroacetic acid, preferably, the scale inhibitor is used in an amount of between 0.005 and 10 wt%, preferably between 0.05 and 7.5 wt%, and most preferably between 0.4 wt% and 5 wt%, based on the total weight of the aqueous acidizing treatment fluid. The amount of scaling inhibitor specified herein refers to the active content of the scaling inhibitor. Thus, if 1 wt% of a scale inhibitor solution with 50 % active content is added to the aqueous acidizing treatment fluid, the amount of scaling inhibitor present in the fluid, according to the present disclosure, is 0.5 wt%.

Preferably, in addition to the scale inhibitor a chelating agent is also used. It has been found that with the use of the scale inhibitor according to the present disclosure, lower amounts of chelating agent could be used, and vice versa, further lowering the costs and environmental burden.

Suitable chelating agents can comprise any agent capable of chelating one or more salts formed during the acidization. The chelating agent may be an organic or an inorganic chelant. In some embodiments, the chelating agent comprises compounds that are monodentate, bidentate, tridentate, tetradentate, pentadentate, hexadentate, septadentate, octadentate, or a combination thereof.

Exemplary chelating agents include lactic acid, malonic acid, fumaric acid, citric acid, tartaric acid, glutamic acid diacetic acid (GLDA), methylglycine diacetic acid (MGDA), 1 , 1 ,4,4- butanetetracarboxylic acid, 1 ,2,3,4-butanetetracarboxylic acid, 4,5-imidazoledicarboxylic acid, phosphonic acid, 3-chloropropyl phosphonic acid, aminotris (methylene phosphonic acid) (ATMP), bis(hexamethylenetriaminepenta-(methylene phosphonic acid) (BHMTPMPA), 1 ,2- cyclohexanediaminetetraacetic acid (CDTA), 1 ,4,7,10-tetraazacyclododecane-1 ,4,7,10- tetraacetic acid (DOTA), 1 ,4,7,10-tetraazacyclodedecane-1 ,4,7,10-tetraphosphonic acid (DOTP), diethylenetriamineepenta-acetic acid (DTPA), diethylenetriaminepenta (methylene phosphonic acid) (DTPMP), ethanol-diglycinic acid (EDG), ethylenediamineteraacetic acid (EDTA), ethylene diamine tetra (methylene phosphonic acid) (EDTMPA), ethylenedioxybis(ethyliminodi(acetic acid)) (EGTA), hydroxyamino-carboxylic acid (HACA), 1 - hydroxyethane 1 ,1 -diphosphonic acid (HEDP), N-hydroxyethyl-ethylenediamine-triacetic acid (HEDTA), hydroxyethyleneiminodiacetate (HEIDA), N"-carboxymethyldiethylenetriamine- N,N,N',N''-tetraacetate (HDTPA), iminodiacetic acid (IDA), N,N'-bis(carboxymethyl)glycine (NTA), nitrolo-tripropionic acid (NTP), nitrilotrimethylenephosphonic acid (NTMP), sodium hexametaphosphate (SHMP), triethylenetetramine-N,N,N',N'',N'", N"'-hexaacetic acid (and N,N'- bis( butanamide) derivative) (TTHA), terpyridine, bypyridiene, triethylenetetramine, biethylenetriamine, bis(hexamethylenetriamine) (BHMT), and salts, derivatives and mixtures thereof.

Preferably, a chelating agent is used which does not comprise nitrogen. A preferred chelating agent comprises at least one monovalent carboxylate salt group and furthermore comprises a carbon chain carrying at least five hydroxyl groups. The term “hydroxyl group” is used herein to refer to a functional group consisting of a hydrogen atom covalently bonded to an oxygen atom (denoted as -OH). The term “hydroxyl group” as used herein, does not include the -OH moiety of a carboxyl group.

The number of carboxylate groups of the chelating agent n is preferably between 1 and 5. Preferred chelating agents are selected from the group consisting of monovalent salts of glucaric acid, monovalent salts of gluconic acid, monovalent salts of glucoheptonic acid and other stereoisomers of 2,3,4,5,6-pentahydroxyhexanoic acid and 2, 3, 4, 5,6,7- hexahydroxyheptanoic acid. Specific examples are sodium gluconate, sodium glucoheptonate, other stereoisomers of sodium 2,3,4,5,6-pentahydroxyhexanoate and sodium 2,3,4,5,6,7-hexahydroxyheptanoate. Most preferred is the use of sodium gluconate as chelating agent.

Preferably, more than 2 wt% of chelating agent is present in the acidizing treatment solution. Preferably, the molar ratio between the monovalent salt of monochloroacetic acid and the chelating agent lies between 1 : 0.5/n and 1 : 10/n, n being the number of carboxylate groups of the chelating agent. Preferably, no more than 30 wt%, and preferably no more than 25 wt% of chelating agent is present in the acidizing treatment solution, based on the total weight of the acidizing treatment solution. The optimal amount of chelating agent present in the acidizing treatment fluid ranges from about 2 to about 30 wt%, preferably from about 5 to about 27 wt%, and more preferably from about 8 to about 25 wt%, based on the total weight of the acidizing treatment fluid.

The amount of said chelating agent used may be less than equimolar to the concentration of monochloroacetate salt in the acidizing treatment fluid introduced. Normally, chelating agent would have to be added in equimolar amounts of the monochloroacetate salt added. The subterranean earth formation into which the acidizing treatment fluid, the at least one scaling inhibitor, and optionally the chelating agent are introduced preferably comprises carbonate- based rock.

The temperature of the subterranean earth formation into which the acidizing treatment fluid, the at least one scaling inhibitor, and optionally the chelating agent are introduced is preferably at least 80 °C, more preferably at least 100 °C. The temperature of the earth formation preferably does not exceed 200°C, more preferably it does not exceed 180 °C, and most preferably it does not exceed 160 °C.

The present disclosure is further directed to an aqueous acidizing treatment fluid comprising

(i) a monovalent salt of monochloroacetic acid;

(ii) at least one scaling inhibitor comprising a homopolymer of maleic acid or acrylic acid or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200, or a salt thereof; and

(iii) optionally, a chelating agent, wherein the homopolymer or copolymer optionally contains one or more phosphonic or sulfonic functional groups, and wherein total number of carboxyl groups is calculated from the weight average molecular weight of the homopolymer or copolymer as determined by size exclusion chromatography relative to polymethacrylic acid standards.

The monovalent salt of monochloroacetic acid is preferably present in the acidizing treatment fluid in an amount of at least 3 wt%, preferably at least 5 wt% and most preferably at least 10 wt%, based on the total weight of the acidizing treatment fluid. The optimal amount of monovalent salt of monochloroacetic acid present in the acidizing treatment fluid ranges from about 3 to about 20 wt%, preferably from about 5 to about 18 wt%, more preferably from about 6 to about 16 wt%, and most preferably from about 8 to about 15 wt%, based on the total weight of the acidizing treatment fluid.

As is shown in the examples, a mixture of monochloroacetic acid salts in a concentration of above 2 wt% will form a precipitation with calcium carbonate. However, with the addition of a scaling inhibitor according to the disclosure, this precipitation can be avoided and monochloroacetic acid salts may be used in concentrations above 8 wt%, or even up to 10 wt%.

Accordingly, the acidizing treatment fluid of the present invention may contain from about 3 to about 20 wt% monovalent salt of monochloroacetic acid and from about 0.005 to about 7.5 wt% scaling inhibitor, preferably from about 5 to about 18 wt% monovalent salt of monochloroacetic acid and from about 0.05 to about 5 wt% scaling inhibitor, more preferably from about 6 to about 16 wt% monovalent salt of monochloroacetic acid and from about 0.4 to about 2 wt% scaling inhibitor, and most preferably from about 8 to about 15 wt% monovalent salt of monochloroacetic acid and from about 0.4 to about 2 wt% scaling inhibitor, based on the total weight of the acidizing treatment fluid.

The aqueous acidizing treatment fluid according to the description may further comprise one or more compounds selected from the group of mutual solvents, anti-sludge agents, (waterwetting or emulsifying) surfactants, corrosion inhibitors, corrosion inhibitors intensifiers, foaming agents, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, stabilizers, rheology modifiers, breakers, salts, brines, pH control additives such as further acids and/or bases, bactericides/biocides, particulates, crosslinkers, salt substitutes (such as tetramethyl ammonium chloride), relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, combinations thereof, or the like.

A mutual solvent is a chemical additive that is soluble in oil, water, acids (often HCI based), and other well treatment fluids. 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 emulsions. Suitable mutual solvents are ketones, alcohols or esters.

The surfactant can be any surfactant known to the person skilled in the art for use in oil and gas wells. Preferably, the surfactant is a nonionic, amphoteric, anionic or cationic surfactant, even more preferably a cationic surfactant.

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.

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

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 2.0 volume% on total fluid.

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.

One or more salts may be used as rheology modifiers to modify the rheological properties (e.g., viscosity and elastic properties) of the treatment fluids. These salts may be organic or inorganic. When adding salts care should be taken not to detrimentally affect the pH and therewith detrimentally affect the hydrolyzation rate.

Alternative rheology modifiers may include organic or inorganic gelling agents and/or viscosifiers. Examples of commonly used rheology modifiers include, but are not limited to, biopolymers, polysaccharides such as guar gums, xanthan gum, and derivatives thereof, cellulose derivatives such as hydroxyethyl cellulose (HEC), viscoelastic surfactants, and synthetic polymers and oligomers such as polyethylene glycol) [PEG], poly(diallyl amine), poly(acrylamide), poly(aminomethyl propyl sulfonate) [AMPS polymer], poly(acrylonitrile), poly(vinyl acetate), poly(vinyl alcohol), poly(vinyl amine), poly(vinyl sulfonate), poly(styryl sulfonate), poly(acrylate), poly(methyl acrylate), poly(methacrylate), poly(methyl methacrylate), poly(vinyl pyrrolidone), poly(vinyl lactam), and co-, ter-, and quaterpolymers of the following (co-)monomers: ethylene, butadiene, isoprene, styrene, divinyl benzene, divinyl amine, 1 ,4-pentadiene-3-one (divinyl ketone), 1 ,6- heptadiene-4-one (diallyl ketone), diallyl amine, ethylene glycol, acrylamide, AMPS, acrylonitrile, vinyl acetate, vinyl alcohol, vinyl amine, vinyl sulfonate, styryl sulfonate, acrylate, methyl acrylate, methacrylate, methyl methacrylate, vinyl pyrrolidone, and vinyl lactam. Yet other rheology modifiers include clay- based viscosifiers, especially laponite and other small fibrous clays such as the polygorskites (attapulgite and sepiolite). When using polymer-containing viscosifiers, the viscosifiers may be used in an amount of up to 5% by weight of the fluid. The use of brines is known in the art. Any brine chosen should be compatible with the formation and should have a sufficient density to provide the appropriate degree of well control.

Additional salts may be added to a water source, e.g., to provide a brine, and a resulting treatment fluid, in order to have a desired density. 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. Preferred suitable brines may include seawater and/or formation brines.

It is noted that various elements of the present invention, including but not limited to preferred ranges for the various parameters, can be combined unless they are mutually exclusive.

The invention will be elucidated by the following examples without being limited thereto or thereby.

Examples

Molecular weight measurement Molecular weights were determined by conventional size exclusion chromatography (SEC) relative to polymethacrylic acid (PMA) standards, with refractive index (Rl) and ultraviolet (UV) detectors, under the conditions listed below. The analyses were performed on the samples as received. Solutions were prepared by diluting with the eluent to the desired concentration. The samples were analyzed using the Wyatt MALS system. Only the Rl and UV detector signals were used for data evaluation. The base column used was a PL Aquagel-OH 30 column, unless the molecular size of the sample was too high. In such cases, a TSKgel GMPWxl column was used instead.

Example 1 (comparative): Dissolution of CaC03 in the presence of SMCA

To study the forming of a precipitate, 750 g of 6 wt% SMCA (pH about 8-9) solution was added to a stirred 1 L reactor. 19.5 g of calcium carbonate powder was added to the mixture via a funnel. The reactor was closed, and the headspace was filled with 3 barg nitrogen gas. A temperature probe was continuously measuring the temperature of the solution. This solution was then heated with an oil bath to 120 °C for about 5 h. A first sample was taken from the reactor using a dip tube and the chloride concentration was measured by titration to check if SMCA was completely converted to acid. After 5 h the heating was stopped, and the temperature of the reaction mixture was lowered to 80 °C at ambient pressure. A second sample of 25 ml. was drained from the reactor and transferred to a glass vial. This sample was kept at a constant temperature of 40 °C in an oil bath. After 24 h it was noticed that the sample had become completely solid. This experiment was repeated using different solutions of SMCA varying between 2 and 6 wt% SMCA in an aqueous solution (based on total weight of the solution in the reactor). Also the calcium carbonate was equimolar added to these solutions. As can be seen in Table 1 only the mixture containing 2 wt% SMCA gave a clear solution after reaction. These results demonstrate that SMCA concentrations above 2 wt% form precipitation of calcium salts when reacting with calcium carbonate. Table 1 : Results of SMCA solutions of different concentrations with added calcium carbonate

Example 2: Dissolution of CaC03 in the presence of SMCA and commercial scaling inhibitors

Dissolution experiments similar to those of Example 1 were repeated but now 6 wt% of SMCA was used in the presence of a scaling inhibitor. The selected scaling inhibitors can be found in Table 2. The experiments were performed using 20 grams acidizing liquid at ambient pressure. The aqueous acidizing liquid solution was made comprising 6 wt% SMCA and 1 wt% scale inhibitor solution (with 50% active content) where the remaining liquid is demineralized water. When active content deviates from 50%, the amount of scale inhibitor added to the formulation is adapted accordingly. Also 0.44 g of CaC0 3 was added to the mixture. The vial containing the mixture was sealed with a plug and a small opening in the plug allowing release of CO2 formed during dissolution reaction. The vial is placed in an oil bath with a temperature of 80 °C until all solid CaC0 3 has been dissolved (here, a clear solution is necessary at the start of the test). After this, the vials were put in an oven of 40 S C for 3 days and after that another 2 days at 30 S C. This procedure was repeated with all the scale inhibitors shown in Table 2.

Table 2: Results of 6 wt% SMCA solutions with 0.5 wt% different commercial scaling inhibitors and added calcium carbonate

* homopolymer of maleic acid; tcopolymer of maleic acid and acrylic acid;

§ homopolymer of acrylic acid; PESA = polyepoxysuccinic acid;

Acumer 4300 = multipolymer;

Dequest P9300 = copolymer of acrylic acid (AA) and 2-acrylamide-2-methylpropane sulfonic acid (AMPS)

17

As can be seen from the results in Table 2, the samples containing scaling inhibitors comprising a homopolymer of maleic acid, a homopolymer of acrylic acid, or a copolymer of maleic acid and acrylic acid, having a total number of carboxyl groups between 5 and 200 were completely clear after 72 h at 40 °C. Furthermore, of these scaling inhibitors, those having a total number of carboxyl groups between 7 and 100 remained completely clear after 48 h at 30 °C. It is also demonstrated here that scale inhibitors based on polymers other than maleic acid and acrylic acid homopolymers or copolymers (e.g., polyepoxysuccinic acid-based, AA/AMPS-based or multipolymers, i.e., a mix of polymers) do not prevent precipitation of solids at 80 °C and/or at 40 °C. It is also shown that scale inhibitors based on maleic acid and/or acrylic acid homopolymers or copolymers, but with a higher total number of carboxyl groups (e.g., Sokalan PA 110S) do not work at low temperatures.

Example 3: Inhibition effect of scaling inhibitors comprising a homopolymer of maleic acid or a copolymer of maleic acid and acrylic acid after prolonged storage at 40 °C

Dissolution experiments similar to those of Example 2 were repeated with 8 wt% SMCA in the presence of different concentrations of scale inhibitors based on a homopolymer of maleic acid or a copolymer of maleic acid and acrylic acid. 0.59 g CaC03 was added to each sample. The samples were placed in an oil bath with a temperature of 80 °C until all solid CaC03 had been dissolved. After this, the samples were stored in an oven at 40 °C. In Table 3 the results are shown of the precipitation tests after storage for 4 days (using the same classification as Example 2). Table 3: Results of precipitation tests using 8 wt% SMCA solution with added calcium carbonate and differing concentrations of scale inhibitor after 4 days at 40 °C

copolymer of maleic acid and acrylic acid; * homopolymer of maleic acid As can be seen from the results in Table 3, samples containing as little as 0.4 wt% scaling inhibitor based on a homopolymer of maleic acid or a copolymer of maleic acid and acrylic acid remained clear after storage at 40 °C for 4 days. Example 4: Inhibition effect of polymaleic acid-based scaling inhibitor with increased concentration of SMCA

Dissolution reactions similar to those of Example 2 were performed using 20 grams acidizing liquid at 80 S C until all CaC03 was dissolved. After that, the samples were kept at 30 S C for two days and observed afterwards for solids formation. The experimental results are summarized in Table 4 (using the same classification as Example 2). It was found that SMCA concentrations as high as 10 wt% could be used in combination with at least 2 wt% of the polymaleic acid-based scale inhibitor Belclene 245, without suffering precipitation. In these experiments the molar ratio of SMCA and CaC03 was kept constant.

Table 4: Observations of solids formation in solutions where both SMCA and SI (Belclene 245) concentrations have been varied. Example 5: Inhibition effect of polymaleic acid-based scaling inhibitor and chelating agent with increased concentrations of SMCA

Dissolution experiments similar to those of Example 4 were carried out to investigate the effect of using a chelating agent in combination with a scaling inhibitor. To limit the number of experiments, only one scale inhibitor was used (Belclene 245). The scale inhibitor concentration used was 0.5 wt%. The chelating agent, sodium gluconate (NaG), was added equimolar to the concentration of SMCA. The dissolution reaction was performed using 20 grams acidizing liquid at 80 S C until all CaC03 was dissolved. After that, the samples were kept at 30 S C for two days and observed afterwards for solids formation. The experimental results are summarized in Table 5 (using the same classification as Example 2). It was found that samples containing a chelating agent and a scaling inhibitor remained clear after storage at 30 °C for 2 days even with a SMCA concentration as high as 13 wt%. When the scaling inhibitor was not added, precipitation began with a SMCA concentration of 13 wt%. In these experiments, the molar ratio of SMCA and CaC03 was kept constant. Table 5: Effect of scale inhibitor (Belclene 245) and chelating agent (NaG) on precipitation of Ca-salts while dissolving CaCC>3 in a solution comprising different concentrations of SMCA Example 6: Dissolution of CaC0 3 in the presence of SMCA or glycolic acid and commercial scaling inhibitors

Example 2 was repeated with glycolic acid (3.9 wt%) replacing the SMCA in equimolar amount. The commercial scale inhibitors used in this experiment are listed in Table 6. The numbers represent the temperature ( S C) at which precipitation of solids was observed. It can be seen from Table 6 that the dissolution experiments using glycolic acid showed precipitation of calcium salts at 50 °C, whereas the same experiments using SMCA as a precursor for glycolic acid showed no precipitation even at 30 °C. Table 6: Temperature at which precipitation was observed in dissolution experiments using glycolic acid or SMCA

* homopolymer of maleic acid; copolymer of maleic acid and acrylic acid; § homopolymer of acrylic acid

Whilst the invention has been described with reference to an exemplary embodiment, it will be appreciated that various modifications are possible within the scope of the invention. In this specification, unless expressly otherwise indicated, the word ‘or’ is used in the sense of an operator that returns a true value when either or both of the stated conditions is met, as opposed to the operator ‘exclusive or’ which requires that only one of the conditions is met. The word ‘comprising’ is used in the sense of ‘including’ rather than to mean ‘consisting of. All prior teachings acknowledged above are hereby incorporated by reference. No acknowledgement of any prior published document herein should be taken to be an admission or representation that the teaching thereof was common general knowledge in Europe or elsewhere at the date hereof.