WO2013160334A1 - Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur - Google Patents

Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur Download PDF

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Publication number
WO2013160334A1
WO2013160334A1 PCT/EP2013/058457 EP2013058457W WO2013160334A1 WO 2013160334 A1 WO2013160334 A1 WO 2013160334A1 EP 2013058457 W EP2013058457 W EP 2013058457W WO 2013160334 A1 WO2013160334 A1 WO 2013160334A1
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Prior art keywords
acid
composition
salt
glda
formation
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PCT/EP2013/058457
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English (en)
Inventor
Hisham Nasr-El-Din
Cornelia Adriana De Wolf
Salaheldin Mahmoud Ahmed Ahmed ELKATATNY
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Akzo Nobel Chemicals International B.V.
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Priority to CA2875725A priority Critical patent/CA2875725A1/fr
Priority to US14/406,421 priority patent/US20150141302A1/en
Priority to EP13728152.3A priority patent/EP2861691A1/fr
Priority to PCT/EP2013/061472 priority patent/WO2013189731A1/fr
Priority to JP2015516551A priority patent/JP2015529691A/ja
Publication of WO2013160334A1 publication Critical patent/WO2013160334A1/fr
Priority to PH12014502812A priority patent/PH12014502812A1/en

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    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/02—Well-drilling compositions
    • C09K8/04—Aqueous well-drilling compositions
    • C09K8/06—Clay-free compositions
    • C09K8/08—Clay-free compositions containing natural organic compounds, e.g. polysaccharides, or derivatives thereof
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
    • C09K8/536—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning characterised by their form or by the form of their components, e.g. encapsulated material
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/62—Compositions for forming crevices or fractures
    • C09K8/72—Eroding chemicals, e.g. acids
    • C09K8/74—Eroding chemicals, e.g. acids combined with additives added for specific purposes
    • C09K8/76—Eroding chemicals, e.g. acids combined with additives added for specific purposes for preventing or reducing fluid loss
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
    • C09K8/60—Compositions for stimulating production by acting on the underground formation
    • C09K8/84—Compositions based on water or polar solvents
    • C09K8/86—Compositions based on water or polar solvents containing organic compounds
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/26—Gel breakers other than bacteria or enzymes
    • C—CHEMISTRY; METALLURGY
    • C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
    • C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
    • C09K2208/00—Aspects relating to compositions of drilling or well treatment fluids
    • C09K2208/32—Anticorrosion additives

Definitions

  • the present invention relates to a process to treat a subterranean formation containing filter cake with a chelating agent in order to at least partly remove the filter cake therefrom as well as improve the permeability thereof, all in one step.
  • Subterranean formations from which oil and/or gas can be recovered can contain several solid materials in porous or fractured rock formations.
  • the naturally occurring hydrocarbons, such as oil and/or gas, are trapped by overlying rock formations with lower permeability.
  • the reservoirs are found using hydrocarbon exploration methods and often one of the purposes of withdrawing the oil and/or gas therefrom is to improve the permeability of the formations.
  • the rock formations can be distinguished by their major components and one category is formed by so- called sandstone formations, which contain siliceous materials (like quartz) as the major constituent, while another category is formed by so-called carbonate formations, which contain carbonates (like calcite, chalk, and dolomite) as the major constituent.
  • a third category is formed by shales, which contain very fine particles of many different clays covered with organic materials to which gas and/or oil are adsorbed.
  • Shale amongst others contains many clay minerals like kaolinite, illite, chlorite, and montmorillonite, as well as quartz, feldspars, carbonates, pyrite, organic matter, and cherts.
  • Acidic treatment fluids are known in the art and are for example disclosed in several documents that disclose acid treatment with HCI.
  • several documents disclose the use of chelating agents to increase the permeability of the formation. For example, Frenier, W.W., Brady, M., Al-Harthy, S. et al. (2004), "Hot Oil and Gas Wells Can Be Stimulated without Acids," SPE Production & Facilities 19 (4): 189-199.
  • DOI: 10.21 18/86522-PA show that formulations based on the hydroxyethylaminocarboxylic acid family of chelating agents can be used to increase the production of oil and gas from wells in a variety of different formations, such as carbonate and sandstone formations.
  • US 2006/0102349 suggests that a formation can be treated with an acidic solution containing HEDTA and a betaine surfactant, though no proof of any permeability increase in the formation or of any oil or gas production improvement is given in this document.
  • a filter cake is formed in the formation by the introduction of a material capable of forming an impermeable layer on the walls of the wellbore, often during the drilling of the well, i.e. during the process of making a subterranean formation ready for oil and/or gas production.
  • This filter cake serves the purpose of plugging the flow of the drilling fluid in multiple directions by creating a fast, low-thickness, impermeable layer on the wall of the formation and will so prevent leak-off of the drilling fluids into the formation, which would damage the near wellbore area and thus hinder the flow of oil or gas from the formation into the wellbore. In addition, it prevents premature flow of oil or gas from the formation into the wellbore.
  • the filter cake is removed again to enable the flow of oil and or gas from the reservoir into the wellbore and increase the oil and/or gas production from the same well in a later phase. For this reason a filter cake is removed by a so-called breaker system. Breaker fluids are disclosed in several documents.
  • WO 2012/003356 discloses a breaker fluid containing a hydrolyzable ester of a carboxylic acid and a chelant, an alkyl glycoside or a combination thereof.
  • the chelant may be the monosodium salt of glutamic acid ⁇ , ⁇ -diacetic acid.
  • this document only discloses the removal of filter cake from a core and specifically mentions that the flow of breaker fluid into the formation should be avoided or, in other words, teaches away from further treating any subterranean formation with the same fluid to improve the permeability thereof.
  • Cleaning up filter cakes using a breaker system can cause damage to a subterranean formation by a) dissolving only the near wellbore area, also called face dissolution, or b) creating main channels into the formation, c) incomplete filter cake removal, as a result of a too high reaction rate with the formation rather than with the filter cake.
  • face dissolution, main channels, fractures and/or high-permeability zones may draw the acid away from the target zone, i.e.
  • the filter cake breaking should take place in a controlled and even way, amongst others to prevent premature flowing of subsequent treatment fluids into the formation and to prevent loss of the breaker fluid into the formation.
  • the breaker fluid should dissolve the filter cake so well that the filter cake residues are effectively transported from the formation and do not accumulate again at any place in the formation.
  • the present invention now provides a one-step process comprising introducing into a subterranean formation containing a filter cake a composition containing between 1 and 40 wt% of a chelating agent selected from the group of glutamic acid N,N- diacetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine ⁇ , ⁇ -diacetic acid or a salt thereof (MGDA), N- hydroxyethyl ethylenediamine-N,N',N'-triacetic acid or a salt thereof (HEDTA), and having a pH of below 7, wherein in one step the filter cake is at least partly removed and the subterranean formation is treated.
  • a chelating agent selected from the group of glutamic acid N,N- diacetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine
  • the present invention provides the use of a composition containing between 1 and 40 wt% of a chelating agent selected from the group of glutamic acid N,N-di acetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine ⁇ , ⁇ -diacetic acid or a salt thereof (MGDA), N-hydroxyethyl ethylenediamine-N,N',N'-triacetic acid or a salt thereof (HEDTA), and having a pH of below 7, in a subterranean formation containing a filter cake, to at least partly remove the filter cake and treat the subterranean formation, all in one step.
  • a chelating agent selected from the group of glutamic acid N,N-di acetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine ⁇ , ⁇ -d
  • compositions of the invention dissolve the filter cake more selectively and more completely without causing unwanted dissolution of the formation, like face dissolution or the creation of only a major channel, in comparison with state of the art breaker systems.
  • compositions of this invention are better diverted into the low-permeability zones as a result of the increased viscosity of the composition due to the dissolution of cations from the filter cake prior to the stimulation phase, giving a more diverse network of wormholes or dissolution in formations with a high permeability ratio, i.e. formations with a heterogeneous permeability.
  • the filter cakes are formed from drilling muds, i.e. a liquid having solids suspended therein.
  • the solid parts can contain calcium carbonate, barite, manganese oxides, hematite, and iron oxides.
  • the filter cake contains calcium carbonate.
  • Drilling muds in embodiments of the present invention may further include polymers, biopolymers, clays, polymer additives, like rheology modifiers, polymeric thinners, flocculants, and fluid loss control agents, like starch or xanthan gums, organic colloids to obtain the required viscous and filtration properties, biocides, potassium chloride or similar for clay stabilization, agents to increase the pH like calcium hydroxide, to mitigate corrosion, drag reducers, and oxygen scavengers, like sodium sulfite.
  • the composition used in the invention can be a fluid, a foam or a viscosified composition or an emulsified composition.
  • the composition of the invention contains between 5 and 30 wt% of GLDA, AS DA, MGDA and/or HEDTA on the basis of the total weight of the composition.
  • composition with which the formation is treated is preferably a fluid containing between 5 and 30 wt% on total weight of the fluid of a chelating agent selected from the group of glutamic acid ⁇ , ⁇ -diacetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine ⁇ , ⁇ -diacetic acid or a salt thereof (MGDA), N-hydroxyethyl ethylenediamine-N,N',N'-triacetic acid or a salt thereof (HEDTA), but in some embodiments may also be a foam containing between 5 and 30 wt% on total weight of the foam of a chelating agent selected from the group of glutamic acid ⁇ , ⁇ -diacetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid or a salt thereof (ASDA), methylglycine ⁇ , ⁇ -diacetic acid or a salt thereof (MGDA
  • the composition may be an emulsified composition containing a dispersed phase emulsified in a continuous phase wherein between 5 and 30 wt% on total weight of the dispersed phase of the composition is a chelating agent selected from the group of glutamic acid ⁇ , ⁇ -diacetic acid or a salt thereof (GLDA), aspartic acid ⁇ , ⁇ -diacetic acid (ASDA), methylglycine N,N-diacetic acid or a salt thereof (MGDA), and N-hydroxyethyl ethylenediamine- ⁇ , ⁇ ', ⁇ '- triacetic acid or a salt thereof (HEDTA).
  • GLDA glutamic acid ⁇ , ⁇ -diacetic acid or a salt thereof
  • ASDA aspartic acid ⁇ , ⁇ -diacetic acid
  • MGDA methylglycine N,N-diacetic acid or a salt thereof
  • HEDTA N-hydroxyethyl ethylenediamine- ⁇ , ⁇ ', ⁇ '
  • Such emulsified compositions in some embodiments in addition may contain an emulsifying agent in an amount of 0.01 to 10 vol % on total volume of the composition, wherein the emulsifying agent may be chosen from the group of cationic emulsifiers, such as emulsifiers containing quaternary ammonium group- containing components.
  • the emulsified composition contains at least 10 vol % of the continuous phase on total volume of the composition, wherein the continuous phase may contain a liquid chosen from the group of diesel, light crude oil or xylene.
  • the chelating agents present in the foams or compositions of this invention are easier to foam and viscosify at elevated temperatures, which is a benefit when they are used in subterranean formations, where the temperature is generally higher than room temperature.
  • the foams or viscosified compositions of the invention have an excellent balance between the stability of the foam and/or the increased viscosity and an adjustable breakdown thereof to again give the lower viscous solutions, which is a benefit in formation treatment applications, as then the foams or viscosified compositions do not block or plug the less permeable parts of a formation unnecessarily long, i.e. they block the flow of liquids generally for the time needed to break the filter cake but not very long thereafter, so the remaining fluid can penetrate into the formation to increase the permeability and stimulate the subterranean formation. Also for this reason in many embodiments they need a lower amount of breakers than state of the art foams or viscosified compositions.
  • the viscosifying agent and the chelating agent in combination had a better viscosity build-up than any of these components separately, i.e. worked synergistically.
  • the foams or viscosified compositions have an excellent combination of properties to remove the filter cake and improve the permeability of the formations.
  • foams or viscosified compositions from these chelating agents which are more suitable for treating a subterranean formation than those made from state of the art acidizing fluids like HCI-based fluids.
  • the foams and viscosified compositions containing the chelating agents of the present invention give a better performance in treating subterranean formations in that they give an improved permeability, require fewer further additives, which was not expected given the fact that chelating agents carry opposite charges in their molecular structure, i.e. unlike many other acids have a molecular structure in which the nitrogen atom is regularly slightly positively charged and the carboxylate group is negatively charged, depending on the pH of the solution.
  • the amounts of chelating agent, foaming agent, and viscosifying agent in wt% or ppm are based on the total weight of the composition in which they are present, the amount of gas in vol% is on the basis of the total volume of the composition.
  • Viscosified composition is defined in this application as a composition that has a higher viscosity than the same composition without a viscosifying agent when using a Grace 5600 HPHT rheometer equipped with Hastelloy C-276 internals at 20°C or another relevant temperature as specified herein.
  • a B5 bob was used for this application, which required a sample volume of 52 cm 3 .
  • the test was applied by varying the shear rate from 0.1 to 1 ,000 s ⁇ 1 .
  • the viscosity of the viscosified composition is higher than 10 cp, more preferably higher than 50 cp at a shear rate of 100 s ⁇ 1 .
  • foams like viscosified compositions also have a viscosity higher than the liquid not containing the foaming agent.
  • foams are defined as viscosified compositions that contain an intentionally added gas.
  • the subterranean formation in one embodiment can be a carbonate formation, a shale formation, or a sandstone formation.
  • the term treating in this application is intended to cover any treatment of the formation with the composition. It specifically covers treating the formation with the composition to achieve at least one of (i) an increased permeability, (ii) the removal of small particles, and (iii) the removal of inorganic scale, and so enhance the well performance and enable an increased production of oil and/or gas from the formation. At the same time, it may cover cleaning of the wellbore and descaling of the oil/gas production well and production equipment.
  • the chelating agent is preferably present in the composition in an amount of between 5 and 30 wt%, more preferably between 10 and 30 wt%, even more preferably between 15 and 25 wt%, on the basis of the total weight of the composition.
  • the chelating agent in a preferred embodiment is GLDA, ASDA or HEDTA, more preferably GLDA or HEDTA, even more preferably GLDA.
  • the process of the invention is preferably performed at a temperature of between 35 and 400°F (about 2 and 204°C), more preferably between 77 and 400°F (about 25 and 204°C). Even more preferably, the compositions are used at a temperature where they best achieve the desired effects, which means a temperature of between 77 and 350°F (about 25 and 177°C), most preferably between 150 and 350°F (about 65 and 177°C).
  • the process of the invention is preferably performed at a pressure between atmospheric pressure and fracture pressure, wherein fracture pressure is defined as the pressure above which injection of the fluids will cause the formation to fracture hydraulically.
  • fracture pressure is defined as the pressure above which injection of the fluids will cause the formation to fracture hydraulically.
  • Salts of GLDA, AS DA, HEDTA, and MGDA that can be used are the alkali metal, alkaline earth metal, or ammonium full and partial salts. Also mixed salts containing different cations can be used.
  • the sodium, potassium, and ammonium full or partial salts of GLDA, AS DA, HEDTA, and MGDA are used.
  • compositions of the invention are preferably aqueous compositions, i.e., they preferably contain water as a solvent for the other ingredients, wherein the water can be, e.g., fresh water, aquifer water, produced water, seawater or any combination of these waters, though other solvents may be added as well, as further explained below.
  • water can be, e.g., fresh water, aquifer water, produced water, seawater or any combination of these waters, though other solvents may be added as well, as further explained below.
  • the pH of the compositions of the invention and as used in the process can range from 1 .7 to 7. Preferably, however, it is between 2 and 7, more preferably between 2 and 5, and most preferably between 3.5 and 5, as in the very acidic range of 1 .7 to 3.5 some undesired side effects may be caused by the compositions in the formation, such as too fast dissolution of carbonate giving excessive CO 2 formation or an increased risk of reprecipitation. For a better carbonate dissolving capacity it is preferably more acidic. On the other hand, it must be realized that highly acidic solutions are more expensive to prepare and are very corrosive to well completion and tubulars, especially at high temperatures.
  • the most preferred pH of the composition used in the process of the present invention is between 3.5 and 5.
  • the composition may contain other additives that improve the functionality of the stimulation action and minimize the risk of damage as a consequence of the said treatment, as is known to anyone skilled in the art.
  • the several additives can be part of a main treatment composition but can be included equally well in a preflush or postflush composition.
  • the composition of the invention is effectively a kit of parts wherein each part contains part of the components of the total composition, for example, one part that is used for the one-step treatment contains the composition of the invention and one or more other parts contain one or more of the other additives, such as for example a surfactant or mutual solvent.
  • the gas is preferably present in the foam in an amount of between 50 and 99 vol%, more preferably between 50 and 80 vol%, even more preferably 60-70 vol % on total foam volume.
  • the foaming agent in one embodiment is a surfactant.
  • it is a water-soluble surfactant, as the foams of the invention are preferably water-based.
  • the foaming agent in one embodiment is used in an amount of between 10 ppm and 200,000 ppm based on the total weight of the foam, preferably between 10 ppm and 100,000 ppm, even more preferably between 100 and 50,000 ppm, most preferably between 100 and 10,000 ppm.
  • the viscosifying agent is preferably present in an amount of between 0.01 and 3 wt%, more preferably between 0.01 and 2 wt%, even more preferably between 0.05 and 1.5 wt% on total weight of the viscosified composition or foam.
  • the gas in one embodiment is selected from the group of N 2 , CO, CO 2 , natural gas, oxygen or mixtures thereof, like air.
  • N 2 , CO 2 , air, or natural gas is used.
  • the viscosifying agent in one embodiment can be chosen from carbohydrates, or polysaccharides such as cellulosic derivatives, guar or guar derivatives, xanthan, carrageenan, starch biopolymers, several gums, polyacrylamides, polyacrylates, viscoelastic surfactants [e.g, amide oxides, carboxybetaines].
  • Foam-forming surfactants include anionic, cationic, amphoteric, and nonionic surfactants in increasing order of performance.
  • Foaming agents include, but are not limited to, ethoxylated alcohols, polysaccharides, ethoxylated fatty amines, amine oxides, glucosides, sulfonates, and quaternary ammonium salts.
  • the composition of the invention contains a combination of a foaming agent and a viscosifying agent, the foaming agent and the viscosifying agent being chosen from the group of foaming agents and viscosifying agents as further specified in this document.
  • the foaming agent and/or the viscosifying agent are present together with an additional surfactant, which can be a predominantly nonionic, anionic, cationic, or amphoteric surfactant.
  • the foam contains an insoluble component.
  • the foam of the present invention contains a foam extender.
  • Foam extenders are known in the art and are for example disclosed in WO 2007/020592.
  • the viscosified composition of the present invention contains a crosslinking agent which is capable of crosslinking the viscosifying agent and therefore can improve the properties of the viscosified composition and, in embodiments wherein the foam also contains a viscosifying agent, also the foam.
  • Crosslinking agents are known in the art and are for example disclosed in WO 2007/020592.
  • the viscosifying agents include chemical species which are soluble, at least partially soluble and/or insoluble in the chelating agent-containing starting fluid.
  • the viscosifying agents may also include various insoluble or partially soluble organic and/or inorganic fibres and/or particulates, e.g., dispersed clay, dispersed minerals, and the like, which are known in the art to increase viscosity.
  • Suitable vicosifying agents further include various organic and/or inorganic polymeric species including polymer viscosifying agents, especially metal-crosslinked polymers.
  • Suitable polymers for making the metal- crosslinked polymer viscosifying agents include, for example, polysaccharides, e.g., substituted galactomannans, such as guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG), and carboxymethyl guar (CMG), hydrophobically modified guars, guar-containing compounds, and synthetic polymers.
  • polysaccharides e.g., substituted galactomannans, such as guar gums, high-molecular weight polysaccharides composed of mannose and galactose sugars, or guar derivatives such as hydroxypropyl guar (HPG), carboxymethylhydroxypropyl guar (CMHPG), and carboxymethyl guar (CMG), hydrophobically modified guars, gu
  • Crosslinking agents which include boron, titanium, zirconium and/or aluminium complexes are preferably used to increase the effective molecular weight of the polymers and make them better suited for use as viscosity-increasing agents, especially in high-temperature wells.
  • water-soluble polymers effective as viscosifiers include polyvinyl alcohols at various levels of hydrolysis, polyvinyl polymers, polymethacrylamides, cellulose ethers, lignosulfonates, and ammonium, alkali metal, and alkaline earth salts thereof, polyethyleneimines, polydiallyldimethylammonium chloride, polyamines like copolymers of dimethylamine and epichlorohydrin, copolymers of acrylamide and cationic monomers, like diallyldimethylammonium chloride (DADMAC) or acryloyloxyethyltrimethylammonium chloride, copolymers of acrylamide containing anionic as well as cationic groups.
  • DADMAC diallyldimethylammonium chloride
  • acrylamide containing anionic as well as cationic groups copolymers of acrylamide containing anionic as well as cationic groups.
  • water-soluble polymers are acrylic acid-acrylamide copolymers, acrylic acid-methacrylamide copolymers, polyacrylamides, partially hydrolyzed polyacrylamides, partially hydrolyzed polymethacrylamides, polyvinyl alcohol, polyalkylene oxides, other galactomannans, heteropolysaccharides obtained by the fermentation of starch-derived sugar and ammonium and alkali metal salts thereof.
  • cellulose derivatives are used, including hydroxyethyl cellulose (HEC), hydroxypropyl cellulose (HPC), carboxymethyl- hydroxyethyl cellulose (CMHEC) and/or carboxymethyl cellulose (CMC), with or without crosslinkers.
  • HEC hydroxyethyl cellulose
  • HPC hydroxypropyl cellulose
  • CMC carboxymethyl- hydroxyethyl cellulose
  • Xanthan, diutan, and scleroglucan are also preferred.
  • composition of the invention may in addition contain one or more of the group of anti-sludge agents, (water-wetting or emulsifying) surfactants, corrosion inhibitors, mutual solvents, corrosion inhibitor intensifiers, foaming agents, viscosifiers, wetting agents, diverting agents, oxygen scavengers, carrier fluids, fluid loss additives, friction reducers, stabilizers, rheology modifiers, gelling agents, scale inhibitors, breakers, salts, brines, pH control additives such as further acids and/or bases, bactericides/biocides, particulates, crosslinkers, enzymes, emulsifiers, oxydants, salt substitutes (such as tetramethyl ammonium chloride), relative permeability modifiers, sulfide scavengers, fibres, nanoparticles, consolidating agents (such as resins and/or tackifiers), combinations thereof, or the like.
  • the enzymes in preferred embodiments are enzymes that are known to degrade biopol
  • the mutual solvent is a chemical additive that is soluble in oil, water, acids (often HCI-based), and other well treatment fluids ( s e e a l s o http://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.
  • a mutual solvent remove organic films leaving them water-wet, thus emulsions and particle plugging are eliminated.
  • 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
  • a preferred water/oil-soluble ketone is methylethyl ketone.
  • a preferred substantially water/oil-soluble alcohol is methanol.
  • a preferred substantially water/oil-soluble ester is methyl acetate.
  • a more preferred mutual solvent is ethylene glycol monobutyl ether, generally known as EGMBE
  • 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.
  • the surfactant can be any surfactant known in the art or a mixture thereof and include 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 can better be limited in case of sandstone, while in case of carbonate rock anionic surfactants are not preferred.
  • the surfactant (mixture) is predominantly anionic in nature when the formation is a sandstone formation.
  • the surfactant (mixture) is preferably predominantly nonionic or cationic in nature, even more preferably predominantly cationic in nature.
  • 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
  • the anionic surfactants may comprise any number of different compounds, including alkylsulfates, alkylsulfonates, alkylbenzenesulfonat.es, alkyl phosphates, alkyl phosphonates, alkyl sulfosuccinates.
  • amphoteric surfactants include hydrolyzed keratin, taurates, sultaines, phosphatidylcholines, betaines, modified betaines, alkylamidobetaines (e.g. , cocoamidopropyl betaine).
  • the cationic surfactants include alkyl amines, alkyl dimethylamines, alkyl trimethyl amines (quaternary amines), alkyl diethanolamines, dialkylamines, dialkyldimethylamines and less common classes based on phosphonium, sulphonium.
  • the cationic surfactants may comprise quaternary ammonium compounds (e.g., trimethyl tallow ammonium chloride, trimethyl coco ammonium chloride), derivatives thereof, and combinations thereof.
  • Suitable surfactants may be used in a liquid or solid, like powder, granule or particulate, form.
  • 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.
  • 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.
  • 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%.
  • 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.
  • 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.
  • 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.
  • anti-sludge agents stabilize the acid-oil emulsion and include alkyl phenols, fatty acids, and anionic surfactants.
  • 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.
  • DBSA dodecyl benzene sulfonic acid
  • 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 NaCI or KCI.
  • 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.
  • DETU diethyl thiourea
  • DDPB dodecyl pyridinium bromide
  • sulfur compounds such as thiourea or ammonium thiocyanate
  • 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.
  • One or more corrosion inhibitor intensifiers may be added, such as for example formic acid, potassium iodide, antimony chloride, or copper iodide.
  • 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.
  • 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.
  • aromatic sulfonates and carboxylates such as
  • 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.
  • 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 potassium formate
  • cesium formate cesium formate
  • zinc halide salts preferably chloride salts are mixed with chloride salts, bromide salts with bromide salts, and formate salts with formate salts.
  • 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.
  • Further viscosifiers may include natural polymers and derivatives such as xanthan gum and hydroxyethyl cellulose (HEC) or synthetic polymers and oligomers such as poly(ethylene glycol) [PEG], poly(diallyl amine), poly(acrylamide), poly(aminomethyl propyl sulfonate) [AMPS polymer], poly(acrylonitrile), polyvinyl acetate), polyvinyl alcohol), polyvinyl amine), polyvinyl sulfonate), poly(styryl sulfonate), poly(acrylate), poly(methyl acrylate), poly(methacrylate), poly(methyl methacrylate), polyvinyl pyrrolidone), polyvinyl lactam) and co-, ter-, and quarter- polymers of the following (co-)monomers: ethylene, butadiene, isoprene, styrene, divinyl benzene, divinyl amine, 1 ,4-pent
  • Still other viscosifiers include clay-based viscosifiers, platy clays, like bentonites, hectorites or laponites and small fibrous clays such as the polygorskites (attapulgite and sepiolite).
  • the viscosifiers may be used in an amount of up to 5% by weight of the compositions of the invention.
  • 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.
  • the 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 foam, 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.
  • 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.
  • a compatibility test may be performed to identify potential compatibility problems. 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.
  • 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.
  • 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.
  • Salt may also be included to increase the viscosity of the foam or composition and stabilize it, particularly at temperatures above 180°F (about 82°C).
  • pH control additives examples include acids and/or bases.
  • 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.
  • the pH control additive may be an acidic composition.
  • suitable acids may comprise an acid, an acid-generating compound, and combinations thereof.
  • Any known acid may be suitable for use with the compositions of the present invention.
  • acids examples 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 HCI (in an amount compatible with the illite content) and organic acids.
  • acid-generating compounds examples 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. Derivatives and combinations also may be suitable.
  • 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.
  • 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.
  • the pH control additive also may comprise a base to elevate the pH of the composition.
  • suitable bases include, but are not limited to, sodium hydroxide, potassium carbonate, potassium hydroxide, sodium carbonate, and sodium bicarbonate.
  • the composition may optionally comprise a further chelating agent.
  • 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.
  • Such a chelating agent may, e.g., prevent such ions from crosslinking the gelling agent molecules.
  • Such crosslinking may be problematic because, inter alia, it may cause filtration problems, injection problems and/or again cause permeability problems.
  • Any suitable chelating agent may be used with the present invention.
  • 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 diami ne-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.
  • NTA citric acid
  • EDTA nitrilotriacetic acid
  • DTPA diethylene triamine pentaacetic acid
  • the chelating agent may be a sodium or potassium salt.
  • 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.
  • 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.
  • bactericides Any bactericides known in the art are suitable. Biocides and bactericides that protect against bacteria that may attack GLDA, AS DA, MGDA or HEDTA are preferred, in addition to bactericides or biocides that control or reduce typical downhole microorganisms, like sulfate reducing bacteria (SRB).
  • SRB sulfate reducing bacteria
  • bactericides and/or biocides include, but are not limited to, phenoxyethanol, ethylhexyl glycerine, benzyl alcohol, 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.
  • the bactericides are present in the foam in an amount in the range of from about 0.001 % to about 1 .0% by weight of the composition.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the breaker may be formulated to provide a delayed break, if desired.
  • compositions of the present invention also may comprise suitable fluid loss additives.
  • 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.
  • 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.
  • a suitable fluid loss additive is one that comprises a degradable material.
  • 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.
  • polysaccharides such as dextran or cellulose
  • chitins such as dextran or cellulose
  • chitosans proteins
  • aliphatic polyesters poly(lactides); poly(glycolides); poly(glycolide-co-lactides); poly(epsilon-caprolactones); poly(3- hydroxybuty
  • a fluid loss additive may be included in an amount of about 5 to about 2,000 Ibs/Mgal (about 600 to about 240,000 g/Mliter) of the composition. In some embodiments, the fluid loss additive may be included in an amount from about 10 to about 50 Ibs/Mgal (about 1 ,200 to about 6,000 g/Mliter) of the composition. In certain embodiments, a stabilizer may optionally be included in the compositions of the present invention.
  • BHT bottom hole temperature
  • Suitable stabilizers include, but are not limited to, sodium thiosulfate, methanol, and salts such as formate salts and potassium or sodium chloride.
  • 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 Ibs/Mgal (about 120 to about 6,000 g/Mliter) of the composition. 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.
  • 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.
  • Examples of such compounds include aliphatic phosphonic acids such as diethylene triamine penta (methylene phosphonate) and polymeric species such as polyvinyl sulfonate.
  • aliphatic phosphonic acids such as diethylene triamine penta (methylene phosphonate)
  • polymeric species such as polyvinyl sulfonate.
  • 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 4 . Any scale inhibitor that is compatible with the composition in which it will be used is suitable for use in the present invention.
  • 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.
  • 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).
  • 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.
  • pill 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.
  • coated particulates may be suitable for use in the treatment foams 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.
  • Oxygen scavengers may be needed to enhance the thermal stability of the GLDA, ASDA, HEDTA or MGDA. Examples thereof are sulfites and ethorbates.
  • Friction reducers can be added in an amount of up to 0.2 vol%. Suitable examples are viscoelastic surfactants and enlarged molecular weight polymers.
  • 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 amides, formaldehyde.
  • Sulfide scavengers can suitably be an aldehyde or ketone.
  • Viscoelastic surfactants can be chosen from the group of amine oxides, betaine or carboxyl butane-based surfactants.
  • High-temperature applications may benefit from the presence of an oxygen scavenger in an amount of less than about 2 vol% of the solution.
  • compositions can be used at an increased pressure. Often compositions are pumped into the formation under pressure.
  • the pressure used is below fracture pressure, i.e. the pressure at which a specific formation is susceptible to fracture. Fracture pressure can vary a lot depending on the formation treated, but is well known by the person skilled in the art.
  • the composition can be flooded back from the formation. Even more preferably, (part of) the composition is recycled.
  • Indiana limestone and Berea sandstone cores were used to simulate the pay zone formation. Indiana limestone cores were cut from a block with an average porosity of 23 vol% and an average permeability of 80 - 120 mD. Berea sandstone cores have an average porosity of 18 vol% and an average permeability of 50-60 mD.
  • GLDA glutamic acid ⁇ , ⁇ -diacetic acid
  • HEDTA N-hydroxyethyl ethylenediamine ⁇ , ⁇ ', ⁇ '-triacetic acid
  • a-amylase enzyme was obtai ned from Baker Hughes. This type of enzyme contains a stabilizer that can be used up to 250°F (121 °C).
  • the drilling fluid was prepared and mixed as shown in Table 1 .
  • Table 1 Drilling fluid formula for lab scale.
  • the density of the drilling fluid was measured using a mud balance at 77°F (25°C) and it was 9.6-9.8 ppg (1 ,144-1 ,168 kg/m 3 ).
  • the viscosity was measured using a M3600 viscometer at 120°F (49°C) and it was 14 cp.
  • the yield point was measured at 120°F (49°C) and it was 24 l b/1 00 ft 2 (1 .17 kg/m 2 ).
  • the gel strength was measured at 120°F(49°C) for 10 s and 10 min and it was 6 and 8 lb/100 ft 2 (0.29 and 0.39 kg/m 2 ) respectively.
  • the pH was measured at 77°F (25°C) and it was 10. Table 2 summarizes the drilling fluid properties.
  • Table 2 Properties of the drilling fluids.
  • Table 3 Sieve analysis of calcium carbonate particles used to prepare the drilling fluids.
  • a modified HPHT filter press was used to perform the filtration process under static conditions. 1 in. (2.54 cm) thickness x 2.5 in. (6.35 cm) diameter core was used in the modified cell.
  • the drilling fluid was prepared as specified above and placed in the cell. The cell was put in the heating jacket; the system was adjusted at 225°F (107°C) and 300 psi (21 bar) differential pressure.
  • the filter cakes were removed by soaking them for 16 hrs in 200 grams of a 20 wt% GLDA solution. In some experiments the filter cakes were soaked for 24 hrs in a 10 wt% a-amylase enzyme solution prior to the GLDA treatment.
  • the removal efficiency was calculated by comparing the weight of the saturated core before filtration, the weight of the core after filtration, and the weight of the core after the removal process, Equation 1.
  • Wi the weight of the core saturated with water
  • W2 the weight of the core with filter cake
  • W 3 the weight of the core after the removal process
  • Example 1 Influence of enzyme treatment

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Abstract

La présente invention concerne un procédé en une étape consistant à introduire dans une formation souterraine contenant un gâteau de filtration une composition contenant entre 1 et 40 % en poids d'un agent chélateur choisi dans le groupe constitué de l'acide glutamique N,N-diacétique ou de son sel (GLDA), de l'acide aspartique N,N-diacétique ou de son sel (ASDA), de l'acide méthylglycine N,N-diacétique ou de son sel (MGDA) et de l'acide N-hydroxéthyl éthylènediamine N,N',N'-triacétique ou de son sel (HEDTA), le pH de ladite composition étant inférieur à 7. Le gâteau de filtration est au moins partiellement éliminé et la formation souterraine traitée en une seule étape.
PCT/EP2013/058457 2012-04-27 2013-04-24 Procédé en une étape d'élimination du gâteau de filtration et de traitement d'une formation souterraine au moyen d'un agent chélateur WO2013160334A1 (fr)

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CA2875725A CA2875725A1 (fr) 2012-06-18 2013-06-04 Composition contenant un agent chelateur emulsifie et procede pour traiter une formation souterraine
US14/406,421 US20150141302A1 (en) 2012-06-18 2013-06-04 Composition Containing An Emulsified Chelating Agent And Process To Treat A Subterreanean Formation
EP13728152.3A EP2861691A1 (fr) 2012-06-18 2013-06-04 Composition contenant un agent chélateur émulsifié et procédé pour traiter une formation souterraine
PCT/EP2013/061472 WO2013189731A1 (fr) 2012-06-18 2013-06-04 Composition contenant un agent chélateur émulsifié et procédé pour traiter une formation souterraine
JP2015516551A JP2015529691A (ja) 2012-06-18 2013-06-04 乳化キレート剤を含有する組成物および地下層を処理する方法
PH12014502812A PH12014502812A1 (en) 2012-06-18 2014-12-17 Composition containing an emulsified chelating agent and process to treat a subterranean formation

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US201261661001P 2012-06-18 2012-06-18
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WO2014195290A1 (fr) * 2013-06-04 2014-12-11 Akzo Nobel Chemicals International B.V. Procédé pour traiter des formations souterraines à l'aide d'un agent chélatant
WO2016097026A1 (fr) * 2014-12-17 2016-06-23 Basf Se Utilisation de mgda en tant qu'additif dans des procédés de récupération de pétrole brut et/ou de gaz à partir de formations souterraines
WO2018086984A1 (fr) 2016-11-10 2018-05-17 Basf Corporation Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères
EP3277769A4 (fr) * 2015-04-03 2018-12-19 Hppe LLC Compositions et procédés de stabilisation de sols contenant de l'argile
WO2021168315A1 (fr) * 2020-02-20 2021-08-26 Gas Technology Institute Application de solvants écologiques à base d'enzyme pour la récupération de fluides souterrains
US11118095B2 (en) 2016-09-15 2021-09-14 Schlumberger Technology Corporation Compositions and methods for servicing subterranean wells
US11326090B2 (en) 2019-10-18 2022-05-10 King Fahd University Of Petroleum And Minerals Combined thermochemical and chelating agents useful for well cleanup
US11414589B2 (en) 2020-01-22 2022-08-16 King Fahd University Of Petroleum And Minerals Method of removing calcium carbonate-containing oil-based filter cake using a biodegradable acid solution
WO2023009352A1 (fr) * 2021-07-29 2023-02-02 Baker Hughes Oilfield Operations Llc Systèmes de fluide pour dilater des polymères à mémoire de forme et éliminer des gâteaux de boues
GB2556484B (en) * 2015-07-06 2023-02-08 Schlumberger Technology Bv HEDTA based chelants used with divalent brines, wellbore fluids including the same and methods of use thereof
WO2023059866A1 (fr) * 2021-10-08 2023-04-13 Baker Hughes Oilfield Operations Llc Systèmes de fluide pour dilater des polymères à mémoire de forme et éliminer les gâteaux de boues à base d'eau

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EP3277769A4 (fr) * 2015-04-03 2018-12-19 Hppe LLC Compositions et procédés de stabilisation de sols contenant de l'argile
US10351770B2 (en) 2015-04-03 2019-07-16 Integrity Bio-Chemicals, Llc Compositions and methods for the stabilization of clay containing soils
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US11118095B2 (en) 2016-09-15 2021-09-14 Schlumberger Technology Corporation Compositions and methods for servicing subterranean wells
WO2018086984A1 (fr) 2016-11-10 2018-05-17 Basf Corporation Procédé permettant d'augmenter la production d'hydrocarbures à partir de réservoirs pétrolifères
US11655411B2 (en) 2019-10-18 2023-05-23 King Fahd University Of Petroleum And Minerals Thermochemical composition for well cleanup
US11326090B2 (en) 2019-10-18 2022-05-10 King Fahd University Of Petroleum And Minerals Combined thermochemical and chelating agents useful for well cleanup
US11518925B2 (en) 2019-10-18 2022-12-06 King Fahd University Of Petroleum And Minerals Downhole exothermic reaction well bore wall clean up method
US11414589B2 (en) 2020-01-22 2022-08-16 King Fahd University Of Petroleum And Minerals Method of removing calcium carbonate-containing oil-based filter cake using a biodegradable acid solution
US11643912B2 (en) 2020-02-20 2023-05-09 Gas Technology Institute Application of enzyme-based green solvents for the recovery of subsurface fluids
WO2021168315A1 (fr) * 2020-02-20 2021-08-26 Gas Technology Institute Application de solvants écologiques à base d'enzyme pour la récupération de fluides souterrains
WO2023009352A1 (fr) * 2021-07-29 2023-02-02 Baker Hughes Oilfield Operations Llc Systèmes de fluide pour dilater des polymères à mémoire de forme et éliminer des gâteaux de boues
US11725133B2 (en) 2021-07-29 2023-08-15 Baker Hughes Oilfield Operations Llc Fluid systems for expanding shape memory polymers and removing filter cakes
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US11939842B2 (en) 2021-10-08 2024-03-26 Baker Hughes Oilfield Operations Llc Fluid systems for expanding shape memory polymers and removing water-based filter cakes

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