MX2007005574A

MX2007005574A - Composition and method for treating a subterranean formation

Info

Publication number: MX2007005574A
Application number: MXMX/A/2007/005574A
Authority: MX
Inventors: Brady Mark; Milne Arthur
Original assignee: Schlumberger Technology Corporation
Priority date: 2004-11-18
Filing date: 2007-05-09
Publication date: 2008-10-03

Abstract

A method of treating a subterranean formation with a retarded self- diverting fluid system The method includes contacting the formation with a mixture of acid, chelating agent, and betaine surfactant in which the betaine surfactant is mixed with an aqueous solution of the chelating agent in which the pH has been adjusted to a pH of below about 3.0, but above the pH at which the free acid of the chelating agent precipitates, and the resulting fluid system is utilized for both acid fracturing and matrix stimulation, as well as workover procedures such as scale and filter cake removal, especially in high temperature formations.

Description

COMPOSITION AND METHOD FOR THE TREATMENT OF UNDERGROUND TRAINING BACKGROUND OF THE INVENTION The present invention relates to a delayed composition that dissolves in a formation, which establishes deviation by its own action, for the treatment of an underground formation, particularly at high temperatures. It is also related to methods for acid fracture and matrix acidification using the composition. The flow of fluids through porous media, for example, the production of fluids from wells, is controlled by three main factors: the size of the flow path, the permeability of the flow path and the driving force. It is often necessary to stimulate the production of fluids from underground formations when the wells do not have a satisfactory production. Failure in production is typically due to an inadequate or damaged path for fluids flowing from the formation to the drill hole. This damage may be due to the formation inherently having insufficient porosity and / or permeability, or because the porosity and / or permeability has been reduced (or damaged) near the drill hole during the drilling operation and / or completion and / or production. There are two main stimulation techniques: matrix stimulation and fracture. The matrix stimulation is carried out, in sandstones, by injection of a fluid (for example, acid or solvent) to dissolve and / or disperse materials that degrade the production of the well. In carbonate formations, the goal of matrix stimulation is to create new, undamaged flow channels from the formation to the drill hole. The stimulation of The matrix, typically called acidification of the matrix when the stimulation fluid is an acid, is generally used to treat only the region near the perforation hole. In an acidification treatment of the matrix, the acid used (for example, hydrochloric acid for carbonates) is injected at a sufficiently low pressure to avoid fracturing the formation. When the acid is pumped into an underground formation, such as a carbonate formation (limestone or dolomite), at pressures below the fracture pressure, the acid preferably flows within the regions of highest solubility or highest permeability (ie say pores, bags or larger natural fractures). The acid reaction in the region of high solubility or high permeability ideally causes the formation of highly conductive flow channels, large so-called wormholes that are formed approximately normal to the fracture. The creation of wormholes is related to the speed of chemical reaction of acid with the rock. High reaction rates, observed between typical concentrations of undisturbed mineral acids, such as HCl, and carbonates, tend to favor the formation of holes. The acids normally used in field treatments are highly reactive to reservoir conditions and tend to form a limited number of wormholes. A low reaction speed favors the formation of several small diameter holes. It is desirable to take into account wellbore and formation factors (such as temperature and composition of the formation) and adjustment of the treatment parameters (such as acid concentration and injection speed) in such a way that "holes" are formed. worm »dominant which penetrates through the area of nearby drilling hole. However, unless the treatment is properly designed, no wormholes are formed. On the contrary, if the flow of acid is too low, the acid reacts uniformly with formation, which is commonly called compact solution, which dissolves all the rock near the hole and does not penetrate deep into the formation and creates flow paths there. In the fracturing, on the other hand, a fluid is forced into the formation at a pressure above which the rock of the formation will split. This force creates a fairly extended flow path. However, when the pressure is released, the fracture typically closes and the new flow path is not maintained unless the operator provides some mechanism by which the bill remains open. There are two common ways to keep the fracture open. In conventional supported hydraulic fracturing, the fluid that is used to generate or propagate the fracture is viscous and contains a solid reinforcing agent that is trapped in the fracture when the pressure is released, preventing the fracture from closing. In acid fracturing, also known as acidification of the fracture, the fracture is generated or subsequently treated with an acid. However, in this case, the treatment parameters in the past have been adjusted in such a way that the wormholes are not produced. Rather, the objective has previously been to treat the faces of the fracture with differentially acid. Then, when the pressure is released, the fracture does not close completely because the differential engraving has created a roughness between the faces in such a way that they no longer fit and there are spaces where the material has been removed. Ideally, the differential acid treatment forms flow channels, usually in a normal manner that follows along the fracture faces of the drill hole to the tip, which improves production. Currently, the acidification treatments of the matrix are interfered by at least three serious limitations: (1) inadequate radial penetration; (2) incomplete axial distribution and (3) corrosion of the pumping line and drill hole. Although the following discussion will focus mostly on the acidification of the matrix, similar problems affect the methods of acid fracturing in such a way that the discussion is completely applicable to both types of acid treatment. The first problem with acid treatment, inadequate radial penetration, is caused by the reaction between the acid introduced into the formation and the material in the drill hole and / or the formation matrix, with which it comes in first contact . The material and / or formation first contacts the acid normally in or near the drill hole such that the formation near the drill hole is treated properly and the parts of the formation further away from the drill hole ( when it moves quickly, outside the perforation hole) they remain untouched by the acid, since all the acid reacts before it can reach them. In fact, the dissolution of the material and / or the formation found by the acid can be so effective that the acid is essentially spent in the time it reaches a few inches beyond the perforation gap. A second problem that limits the effectiveness of the acidification technology of the matrix is the incomplete axial distribution. This problem is related to the incomplete axial distribution. This problem is related to the proper placement of the fluid containing the acid, i.e., which ensures that the fluid is delivered to the desired zone (s) (i.e., the area requiring the stimulation) instead of another zone or zones. More particularly, when an acid formation is injected, the acid begins to dissolve the more reactive material or which contacts first in the drill hole and / or matrix. Depending on the reactivity of the acid with the matrix and the flow rate of the acid towards the reaction site, by continuing to pump acid into the formation, a dominant channel is often created through the matrix. If acid continues to be pumped into the formation, the acid flows along that newly created channel as the path of least resistance and consequently leaves the remainder of the formation substantially untreated. This behavior is exacerbated by the intrinsic permeability heterogeneity (common in many formations), especially the presence of natural fractures and the high permeability lines in the formation. Again, these regions of heterogeneity essentially attract large amounts of the injected acid, thereby keeping the acid out of reach of other parts of the formation along the drill hole where it is actually desired to go. Therefore, in many cases, a substantial fraction of the productive ranges, which contain hydrocarbon, within the area to be treated are not in contact with sufficient acid to penetrate deep enough (laterally in the case of a vertical drill hole) within the training matrix in an effective way to increase its permeability and consequently its capacity to supply hydrocarbon to the drill hole. This problem of proper placement is particularly inconvenient since the injected fluid preferably migrates to areas of high permeability (the path of least resistance) rather than to the low permeability zones, although it is those latter areas that require acid treatment. (ie, because these are areas of low permeability, the flow of hydrocarbons through them decreases). In response to this problem, numerous techniques have been developed to achieve a more controlled placement of the fluid, diverting the acid away from natural areas of high permeability, and areas already treated, towards the regions of interest. Techniques for controlling acid placement (ie, to ensure effective zone coverage) can be roughly divided into mechanical techniques or chemical techniques. Mechanical techniques include ball sealing agents (balls that are dropped into the drill hole that plug the perforations in the well casing, thus sealing the perforation against the fluid inlet), fillers (particularly fork-type fillers that plug a part of the drill hole which limits the entry of fluid into the perforations around that part of the drill hole) and bridge-type plugs, tubes in coils (flexible tubes deployed by a mechanized reel, through which the acid can be supplied in a more precise location within the drill hole), and mushroom-type connections (which try to achieve the deviation by pumping the acid to the highest possible pressure, thus lowering the pressure that could actually fracture the formation). The chemical techniques can be further divided into techniques that chemically modify the drill hole adjacent to the parts of the formation for which the acid is to be diverted, and techniques that modify the fluid itself containing the acid. The first type involves, for example, particulate materials that form a cake of reduced permeability on the face of the perforation hole which, upon contact with eFál ^ Do, divert the acid towards regions of higher permeability. These temperature materials are oil soluble or water soluble particles that are directed to high permeability zones to plug them and consequently divert the acid flow to the low permeability zones. The second type includes foaming agents, emulsifying agents and gelling agents. Mechanical methods and chemical methods that chemically modify the parts of the formation adjacent to the drill hole at the which it is desired to divert the acid will not be considered here further. The emulsion acid systems and foam forming system are commercially available responses to the problem of deviation, but sometimes the complexity of the operation limits its use. For example, the flow rates of two fluids and the bottom pressure must be meticulously monitored during treatment. Gel gels are commercially available, but are frequently undesirable in matrix acidification since the increase in viscosity makes the fluid more difficult to pump (ie, the same resistance to flow that confers the development of pressure in the formation and it results in the desired deviation, in fact makes these fluids more difficult to locate). Some of the commercially available systems are cross-linked polymer systems, that is, they are linear polymers when pumped, but a chemical agent pumped together with the polymer causes them to aggregate or cross-link once they are in the drill hole, which results in its gelation. Unfortunately, these systems leave a residue in the formation, which damages the formation, resulting in the decrease of hydrocarbon production. In addition, the success of these systems depends in a natural way on a cross-linking reaction that can be difficult to optimize in such a way that it is delayed during pumping but maximized once the chemical compounds are at the bottom or at the end of the hole. , or in training. This reaction is easily interfered with by the chemical conditions of the formation, contaminants in the pumping equipment and other factors. Gelation systems consisting of viscoelastic surfactants can avoid these problems. A gelation system having a viscoelastic surfactant is disclosed in U.S. Pat. 5,979,557 and 6,435,277, which have in common the transferee of the present request. Another gelation system having a viscoelastic surfactant is disclosed in U.S. Pat. 6,399,546 and in the United States patent application n. 10 / 065,144, which have in common the assignee of the present application. Viscoelastic deviation acids (VDAs) were developed for the acidification of the carbonate matrix and may contain certain zwitterionic surfactants, such as those based on betaines (described in U.S. Pat. 6,258,859 and referred to as BET surfactants), an acid, and (for some BET surfactants) a surfactant coagent or (for some BET surfactants) an alcohol. The fluid initially injected has a viscosity very close to that of water, but after a considerable part of it has been spent, or has been consumed, the acid in a carbonate formation that reacts with a large amount of acid, the viscosity increases substantially. Therefore, when they are injected, VDAs enter the most permeable areas, but when they melify, they block the zone or zones and subsequently divert the injected fluid into previously less permeable zones. The success of such systems depends on the ability of the formation to reach with a large amount of acid. Consequently, they are more useful with carbonates that have a large capacity to react with the acid. Another limitation of the acid treatments is the corrosion of the pumping equipment and the well pipe and the coating caused by contact with the acid (worsened by the use of concentrated solutions of mineral acids). To solve the problem of corrosion, conventional acid treatments often add a corrosion inhibitor to the fluid. However, corrosion inhibitors can significantly increase the cost of acidification treatments. Another problem with acid treatments is the precipitation of iron, especially in acid wells (ie, wells in which the hydrocarbon has a relatively high acid content) or carbonate formations. There is a tendency to incrustation of iron sulphide to form in drilling holes and / or formations, but in the process hydrogen sulfide is generated, which is toxic and stimulates corrosion. In addition, dissolved iron tends to precipitate, in the form of iron hydroxide or ferric sulphide, since the acid in the treatment fluid becomes spent and the pH of the fluid increases. The precipitation of iron is very undesirable because it damages the permeability of the formation. Accordingly, acid treatment fluids frequently contain additives to minimize iron precipitation and the development of hydrogen sulfide, for example, by sequestering iron ions in solution using chelating agents such as ethylenediaminetetraacetic acid (EDTA). , for its acronym in English). The United States Patent n. No. 4,888,121 discloses an acidification composition that includes an acid such as HCI; an iron sequestering agent such as citric acid, EDTA or nitrilotriacetic acid (NTA); and a sulfide modifier such as formaldehyde. This composition is established to inhibit the precipitation of ferric hydroxide, ferrous sulfide and free sulfur during the well acidification treatment. Although the treatment fluid described in that patent can assist in the control of iron precipitation, in some situations effective control requires the use of much more material in such a way that the cost of treatment becomes excessive; this is especially true for treatment fluids including EDTA, which have a low acid solubility (e.g., pH < 4).

Another limitation of the known acid treatments is their susceptibility to the temperature of the underground formation. The effects of high formation temperatures, for example, vary widely according to the details of the particular fluid treatment. In some acid treatments, high temperature tends to accelerate the corrosion of metal in the drill hole. In other fluids, the viscosity changes intended do not occur in such a way that the acid does not serve the intended purpose of support and / or deviation. SUMMARY OF THE INVENTION An object of the present invention provides a stimulation method that uses a fluid system that is thermally stable, which establishes deviation by its own action, of delayed action and gives low friction pressures. The delay that is required at high temperatures and to control the placement and permeability is provided by a chelating system that has advantages over most other widely used retardation methods that use emulsion acids. A viscoelastic surfactant that melifies when the stimulation is developed is added to facilitate leakage control, deviation, and drag reduction, all of which are advantageous features over emulsion activity systems where a separate deviation system must be pumped (e.g., polymeric gel, polymer in acid, or viscoelastic surfactant in acid). The fluid system does not use mineral acid to react with the formation due to any acid added to the formulation to adjust the pH does not persist once it is added to the chelant because the acid is consumed in partial neutralization of the alkaline chelator; therefore the blockage is much smaller compared to previous acidic fluids. The methods of the invention include acid fracturing, acidification, deflection, removal of the filter cake and removal of incrustation. In one aspect, these objects are achieved by providing a method for the treatment of an underground carbonate formation comprising the steps of reducing the pH of an aqueous solution of a chelating agent with an acid at a pH of less than about 3, and above the pH value at which the free acid form of the chelating agent precipitates, to form a low pH solution of the chelating agent, and which mixes a BET surfactant with the low pH chelating agent solution. An underground carbonate formation is then brought into contact with the mixture of the BET surfactant and the low pH solution of the chelating agent. In another aspect, the present invention also provides an improved method for the acid treatment of a high temperature underground carbonate formation wherein the improvement comprises contacting the formation of underground carbonate with a mixture of a BET surfactant. and a main phase of low pH in which the main low pH phase is prepared by lowering the pH of an aqueous solution of a chelating agent with an acid at a pH of less than about 3, and above the pH value in which the free acid form of the chelating agent precipitates. [0001] Also an object of the present invention provides a method for the effective treatment of an underground formation, particularly a carbonate formation, at temperatures of approximately 170 ° F (77 ° C) and higher for the stimulation of the production of hydrocarbons from a well. Another configuration of the present invention is to remove the barium carbonate and / or sulfate vario scale from the well in high temperature environments. Still another object of the present invention is to provide a one-step method for high temperature carbonate matrix and acidification of the fracture for the control of leaks and kinetic retardation. Still another object of the present invention is to provide a method for achieving long acid-treated fracture lengths with a delayed acid system which are not grouped by high friction / drag pressure. Still another object of the present invention is to provide a method for acidification of the matrix and fracture in a system that can be loaded with NaBr brine for acidification with a high density fluid in the hard-to-reach areas of the carbonate formations. . Still another object of the present invention is to provide a method for obtaining fracture, propagation and long fracture lengths treated with acid under conditions where the surface pressures are high. Yet another object of the present invention is to provide a method for removal of the filter cake while controlling for excessive leakage in situations in which the filter cake is influenced as a result of erosion occurring faster than expected. This list of some objectives of the present invention is not intended to be exclusive. Other objects, and advantages, of the present invention will become apparent to those skilled in the art from the following description of the presently preferred configurations thereof. BRIEF DESCRIPTION OF THE DRAWINGS Figure 1 is a graph showing the change in viscosity of a treatment fluid to be used in relation to a preferred configuration of the method of the present invention as a function of the amount of the reacted calcium carbonate. DETAILED DESCRIPTION OF THE INVENTION According to a description of the method of the present invention, a system of Fluid is provided for the contact of an underground formation in which temperatures can exceed approximately 170 ° F (77 ° C) and can reach a temperature as high as 450 ° F (220 ° C). The treatment fluid includes a fluid viscoelastic surfactant (VES) fluid system and a chelating agent in an aqueous solution; the pH in the aqueous main phase is adjusted below about 3.0, and preferably at a pH of about 2.8, with a mineral acid. The pH is maintained above the pH at which the ligating acid of the chelating agent would precipitate; this usually means maintaining the pH above about 1. Depending on the conditions in the drill hole or particular formation in which the method to be conducted, it may also be advantageous to include an alcohol (such as methanol, for example, to aid in cleaning) and / or an agent that does not produce emulsion in the fluid system. As is known in the art, a corrosion inhibitor can also be included in the fluid system, but the proportion of the corrosion inhibitor is generally lower than in conventional acid treatment fluids. Methods for pumping fluids into the drill hole according to the method of the present invention to stimulate an underground formation are well known. The person who designs such treatments is a person skilled in the art to whom this disclosure is directed. That person has many tools available to help design and implement treatments for matrix stimulation and acid fracturing, one of which is a computer program commonly referred to as a fracture stimulation model (also known as fracture models, fracture stimulators and fracture placement models). Most of the commercial service companies that provide stimulation services for the oil field offer one or more such stimulation models; for example, a commercial fracture stimulation model that is used with advantage in relation to the method of the present invention is known as FracCADE®. This commercial computer program is a program of design, prediction and monitoring of fracture treatment available at Schlumberger. As is known, the various models of fracture stimulation use information available to the treatment designer that have to do with the training to be treated and the various treatment fluids (and additives) in the calculations, and the output of the program is a pumping program that is used to pump the fracture stimulation fluids in the drill hole. The text "Reservoir Stimulation", third edition, edited by Michael J. Economices and Kenneth G. Nolte, John Wiley & Sons (2000), is an excellent reference book on fracturing and other well treatment; discuss the models of fracture stimulation in chapter 5 (pages 5 to 28) and the appendix to chapter 5 (page A-15). The fluid used in the present method is sometimes referred to as an acid wormhole fluid system with self-deviating action or retarded acidic fluid system with self-deviating action; Although the fluid is active and reactive, it is not a strong acid, so the word acid can be left out of the phrase. In certain configurations when the method of the present invention is used in connection with the fracturing of a formation, due to the fracture area available for the fluid inflow into the drill hole it is increased by the creation of worm holes, not It is necessary to generate a long fracture in the formation. Many of the fluid systems of the present invention have the added advantage of being polymer breakdown agents, or for some of the surfactants and / or micelles in the VES. Another advantage for the method of the present invention is that the operator is able to push the active fluid that dissolves in the formation additionally and more quickly because some volume of the fracture is already taken by the support agent. Another advantage is that the operator can be pumped into a fracture supported at much lower pressures, which is an economic advantage. This would also allow the dissolution in the formation to be carried out at the optimum flow rate for the formation of wormholes in the desired location instead of a flow oriented by need to keep the fracture open. Now returning to the composition of the acid treatment fluid for use in connection with the method of the present invention, the chelating agents useful herein are a known class of materials having many members. The class of chelating agents include, for example, aminopolycarboxylic acids and phosphonic acids and sodium, potassium and ammonium salts thereof. The HEDTA and HEIDA (hydroxyethyliminodiacetic acid) are particularly useful in the present process; the free acids and their salts Na +, K +, NH4 + and Ca ++ are soluble in strong acid as well as at high pH so they can be more easily used at any pH and in combination with any other reactive fluid (eg, HCI). Other members of aminopolycarboxylic acid, including EDTA, nitrilotriacetic acid (NTA), DTPA (diethylenetriaminepentaacetic acid) and cyclohexylenediaminetetraacetic acid (CDTA), are also suitable. At low pH, these latter acids and their salts may be less soluble. Phosphonic acids and their salts, which include aminotri (methylene phosphonic acid) (ATMP), 1-hydroxyethylidene-1,1-phosphonic acid (HEDP), hexamethylenediamintetra (methylene phosphonic acid) ( HDTPMPA, by its name in English), diethylnediaminepentamethylenephosphonic acid (DTPMPA, by its name in English) and 2-phosphonobutane-1, 2,4-tricarboxylic acid are additional examples of materials that function as chelating agents that are suitable for use in connection with the method of the present invention. These phosphonic acids are available from Solutio, Inc., San Luis, MO (United States) as the DEQUEST® phosphonates. Such materials are known in the oil field. However, the above treatments do not inject such fluids into a high temperature formation in such a way as to maintain the optimum formation efficiency of wormholes, nor were they as effective as the methods of the present invention in the creation of wormholes in the formation that extends outside the fracture faces. Particularly preferred chelating agent based dissolution agents are those which contain hydroxyethylaminocarboxylic acids such as hydroxyethylenediaminetriacetic acid (HEDTA), hydroxyethyliminodiacetic acid (HEIDA) or a mixture thereof, as described in the patent of the United States n. 6,436,880, which has the assignee of the present application. The dissolution agent based on the most preferred chelating agent contains HEDTA (sodium, potassium and / or ammonium salts) as the sole chelating agent. The fluid systems containing such chelating agents can be viscosity formers and exhibit a further increase in viscosity upon consumption in the formation. The acid wormhole fluid systems with self-acting for deviation particularly preferred in the invention are those made from solutions of certain surfactants, particularly certain betaines, optionally in conjunction with surfactant coagents or lower alcohols. Examples are described in patents of the United States n. 0 6,399,546 and 6,667,280 and the United States patent application n. ° 2003-01 1 9680, all of which have in common with the assignee of the present application. A preferred fluid system of the invention is made from amidopropyldimethyleneteic betaine (also known as erucilamidopropylbetaine), and a highly preferred system is made from oleylamidopropyldimethylbetaine. These wormhole acidic fluid systems with self-acting for deviation have the important property that they have viscosities similar to that of water when formulated (when the pH is below about 3) but their viscosities increase markedly when the pH increases above a value of about 3 when they react with the carbonate in the underground formation. The preferred surfactants are the betaines. Two suitable examples of betaines are BET-0 and BET-E; the most preferred is BET-O-30. The surfactant in BET-O-30 is oleylamidopropylbetaine. BET-O-30 was designated because it is obtained from the supplier (Roída, Inc. Cranbury, New Jersey, United States) it is called Mirataine BET-O-30 because it contains an amide group of oleyl acid (which includes a group of alkene tail C17H33) and contains about 30% active surfactant; the balance is substantially water, sodium chloride and propylene glycol. An analogous material, BET-E-40, is also available in Roída and contains an erucic acid amide group (which includes a group of alkene glue C21 H41) and is approximately 40% of the active ingredient, with the remainder being substantially water , sodium chloride and isopropanol. The surfactants are supplied in this form, with an alcohol and a glycol, to help in the solubilization of the surfactant water at high concentration, and maintain as a homogeneous fluid at temperatures low. However, surfactants could be obtained and used in other ways. The VES systems, in particular the BET-E-40, optionally contain about 1% of a condensation product of a naphthalenesulfonic acid, for example, sodium polynaphthalenesulfonate, as a rheology modifier, as described in the application publication of the United States patent n. ° 2003-0134751. A chemical name for the surfactant in BET-E-40 is erucilamidopropylbetaine. The concentrates in their BET-E-40 presentation were used in the experiments reported below. BET surfactants, and other VES that are suitable for the present invention, are described in U.S. Pat. 6,258,859. According to that patent, the BET surfactants produce viscoelastic gels when in the presence of certain organic acids, salts of organic acid or inorganic salts; the inorganic salts may be present at a concentration by weight of up to about 30%. Surfactant coagents may be useful in extending the tolerance of the brine, and increasing the concentration of the gel and reducing the sensitivity to cutting of the fluid containing VES, in particular for the surfactants type BET-O. An example given in the United States patent n. No. 6,258,859 is sodium dodecylbenzene sulfonate (SDBS). Other suitable surfactant coagents for BET-O-30 are certain chelating agents such as trisodium hydroethylethylenediamine triacetate. These betaine surfactants can form viscous aqueous gels at high temperature at any electrolyte concentration; these form gels without addition of salt or even in concentrated brines. Fluids can generally be prepared, for example, with water from public supply, water from lakes or creeks or saline water. For a surfactant and given conditions (especially the temperature and time for which a viscosity is required suitable) the salinity and the presence and nature of the surfactant coagents and other optional additives can be adjusted according to the parameters known to those skilled in the art to ensure that the gel will have the desired stability. Any corrosion inhibitor (and solvents for such corrosion inhibitors) used in such fluid systems can also do the curing again (the recovery of the gel after the maximum cut disturbance). The fluid systems used in the method of the present invention have the advantage of requiring a lower concentration of corrosion inhibitor than is required for strong acids at high temperature. [0002] The acid used to neutralize the chelating agent can be any inorganic acid; for example, not limiting, hydrochloric, sulfuric or nitric acid. Rheology is affected mainly by the concentration of acid, not by the type of anion. The acid may optionally be an organic acid (or may include an organic acid) which is preferably formic acid, acetic acid or citric acid. Other acids such as boric acid, lactic acid, methylsulfonic acid and ethylsulfonic acid can be used, although the gels formed using formic acid, acetic acid or citric acid are more stable. The optional alcohol used in the fluid systems which are used in the method of the present invention preferably methanol, but ethanol, propanol, isopropanol, ethylene glycol and propylene glycol can be used for lower temperature applications. One purpose of alcohol is to prevent the formation of plugs when the temperature is low and one of the decomposition products of the surfactant is a high melting fatty acid such as a C22 fatty acid which could be a solid. The amount of alcohol Necessary depends on the temperature and chemical structure of the hydrophobic tail of any fatty acid formed. For example, above about 93 ° C, typically only about 1% methanol is required to prevent the formation of a plug of the BET surfactants. As a rule of the standard for the treatments and acid formulations to be used in connection with the method of the present invention typically comprise the corrosion inhibitors, more preferably small amounts of inhibitors based on the quaternary amines, for example, at a concentration from about 0.2 weight percent to about 1.5%, preferably from about 0.4 to about 1.0%, and most preferably from about 0.2% to about 0.6%. The formic acid can also be used as a corrosion inhibitor, typically at a concentration of about 0.1 to about 2.0 weight percent. All other additives normally used in oilfield treatment fluids, such as, but not limited to, corrosion inhibitor aids, scale inhibitors, biocides, leakage control agents, schist stabilizing agents such as ammonium chloride , tetramethylammonium chloride or cationic polymers, monovalent or polyvalent salts, polyelectrolytes, other surface active agents, buffering agents, anti-emulsion agents, freezing point reducing agents, iron reducing agents, chelating agents for the control of multivalent cations, and others also they may be included as necessary, provided they do not disrupt the structure, stability or subsequent degradability of the surfactant gels. The concentration of surfactant in the fluid systems used in the method of the present invention is typically from about 1 to about 6 weight percent (active ingredient); preferred of approximately 2 to about 4%; more preferably it is about 3%. The amount of surfactant is chosen such that the fluid system forms sufficient viscosity to effectively act as a deviating agent but degradation of the surfactant will reduce that viscosity after the desired time. The concentration of inorganic acid, for example, HCl, is from about 6 to about 20 weight percent, preferably from about 6 to about 15%; more preferably about 12%. The concentration of organic acid, for example, formic acid, is from about 5 to about 20 weight percent, preferably from about 5 to about 10%, more preferably about 6%. The concentration of alcohol, for example, methanol, is from about 0 to about 10 weight percent, preferably from about 1 to about 6%, more preferably about 6%. Except as may be useful in adjusting the pH of the fluid system, there are no restrictions on the order of addition of the components of the compositions that are useful in connection with the present invention when they are being formed. The mixture of surfactant as received, water, inorganic acid and chelating agents, and optional materials such as alcohols, surfactant coagents, organic acids, and salts, can be mixed in any order in the field or in a separate location. Optionally, any one or more of the ingredients can be injected into the underground formation separately, that is something of the mixture that can occur in the drill hole or in the formation. Alternatively, any combination of some of the components may be premixed on site or in a separate location and then another component or components may be added later. The fluids can be batch mixed or mixed in progress. Standard mixing equipment and methods can be used; But special heating and agitation can be used although normally they are not necessary. The heating can be used under conditions of extremely cold environment. The exact amounts of the component ingredients and the specific surfactant or mixture of surfactants and chelating agent or chelating mixture to be used will depend on the desired viscosity, the temperature of use, the desired time before the viscosity has increased above a predetermined value, and other similar factors. Similarly, other fluids used in conjunction with the method of the present invention, such as spacers, fillers and the like, may contain such additives, again so long as they do not interfere with the function of the fluid system. The fluid system according to the method of the present invention can be pumped as the reactive fluid in steps separated by inert gelling fluid steps (which may or may not be a crosslinked polymer), or separated by dissolution fluid stages in the formation, with or without pre-filling or post-filling, for example, in the fracturing of acid to create the fracture geometry treated with acid required. However, it is taken into account that a blocking time based on the actual bottom temperature, for example, in acid fracturing, can be used to maximize the effectiveness of the treatment at temperatures below approximately 200 ° F (93 ° C). C). Above that temperature, the treatment is carried out in terms of conventional acid treatment. It is expected that the treatment with the fluid system according to the method of the present invention will sometimes be sensitive to iron, especially at high temperature. For this reason, a pre-filling treatment with the iron-reducing agent and the chelating agent can be injected before the Fluid system is pumped into some formations and where the pipeline is expected to have a high oxide content and high iron content that can dissolve. Although the formation of the fluid system used in connection with the present invention is compatible with small concentrations of non-emulsifying agents, to prevent emulsions and sludge, it may also be advantageous for pre-filling the well with a mutual solvent, preferably the esters, ethers or alcohols of low molecular weight, and more preferably ethylene glycol monobutyl ether. The method of the present invention can be better understood by reference to the following examples which describe certain preferred configurations of the method, as well as the results of various tests that have been found to be relevant for predicting the function of fluid systems in an underground formation . EXAMPLE 1 An experiment of small initial scale incrustation content was carried out by preparing an active acid formulation with 20% HEDTA dissolved in water and the pH was reduced from about 12 to about 2.8 with HCl, 1% methanol, 0.2 to 0.4% corrosion inhibitor and 7.5% BET-O-40 were added and stirred in a flask. A light gel was formed with a viscosity of approximately 100 cP, at 70 seconds at room temperature (estimated, since the sample was not large enough to measure it.) The formulation was used by using two spatula-filled portions of Calcium hydroxide powder with low agitation performed by agitation of the flask After one minute, no visible signs of additional thickening were observed, however, after 2 to 3 minutes, a dense fluid was produced which remained suspended on the edge of the bottle when it was tilted as It does to pour any liquid, which showed heavy criss-crossing fracture gels. Example 2 The second test was a test to determine the feasibility of using the method of the present invention in reservoirs (simulated with crude oil) which has a high tendency to generate plugging sludge and / or precipitate asphaltenes in the presence of a mixture of HCI or very concentrated organic acid. A fluid was prepared starting with 20% aqueous HEDTA with reduction to a pH of about 2.8 with hydrochloric acid, 1% methanol, 2.6% corrosion inhibitor, 0.3% non-emulsifying agent and 7.5% of BET-O-40 in the presence of 1000 ppm of Fe +++. As shown in Figure 1, the system gelled in the presence of CaCO3; the change in viscosity was more pronounced at low shear strength. The x-axis in Figure 1 is the grams of CaCO3 reacted per liter of this fluid. Example 3 A test was carried out to determine the corrosive effect of the fluid system used in the practice of the method of the present invention as follows. The fluids were prepared with chemical compounds of reactive grade with tap water. One inch by 1, 5 inches (2.5 cm x 3.8 cm) of L80 test coupons and P1 10 steels were numbered for identification, clean, submerged in acetone and weighed, and then stored in a desiccant until use . Corrosivity was evaluated in an autoclave at 270 ° F (1 32 ° C) with exposure time for six hours at 3000 psi (20.7 MPa). After the test, the coupons were rinsed in acetone and washed with soap and water to remove the inhibitor film and corrosion deposits. A final rinse in acetone was completed before weighing again the metal coupons to calculate the corrosion rates. The observed corrosion rates are shown below with a pitting index score which (a pitting index of 3 or less is considered acceptable) was determined by the size and depth of the pitting as shown in the following table: A fluid system was formed with HEDTA, corrosion inhibitor, 1% methanol, 0.3% emulsifying agent and 5.0% BET-O. The inhibition of corrosion is presented in the following table: Those skilled in the art who have the benefit of this disclosure will recognize that certain changes may be made to the component parts of the apparatus of the present invention without changing the manner in which those parts function to achieve their intended result. All these Changes and others which will be clear to those skilled in the art of this description of the preferred embodiments of the invention, are intended to be within the scope of the following non-limiting claims.

Claims

Claims 1 . A method of treating an underground carbonate formation comprising the steps of: a. reducing the pH of an aqueous solution of a chelating agent with an acid to a pH of less than about 3, and above the pH value at which the free acid form of the chelating agent precipitates; b. the mixing of a betaine surfactant with the low pH solution of the chelating agent; and c. contacting an underground carbonate formation with the mixture of the betaine surfactant and a low pH solution of the chelating agent.
2. The method of Claim 1 further comprising the addition of a non-emulsifying agent and / or an alcohol.
The method of Claim 1 or Claim 2 wherein the betaine surfactant is selected from the group consisting of erucilamidopropylbetaine and oleylamidopropylbetaine, and mixtures of such betaine surfactants.
4. The method of any of the preceding claims wherein the chelating agent is HEDTA.
The method of any of the preceding Claims wherein the acid, chelating agent and / or betaine surfactant is pumped alternately with an inert gelled fluid or a dissolution fluid in the formation.
6. The method of any of the preceding Claims wherein the scale or filter cake is dissolved.
7. The method of any of the preceding Claims wherein dissolves a part of the formation.
8. The method of any of the preceding claims wherein the formation fractures. The method of any of the preceding Claims wherein the bottom temperature of the underground formation is in the range of about 93 ° C to about 220 ° C. The method of Claim 1 further comprising the use of a blocking time when the bottom temperature of the underground carbonate formation is below about 93 ° C. Summary It reveals a method of treating an underground formation with a fluid system with its own action for deviation, delayed. The method includes contacting the formation with a mixture of acid, chelating agent and betaine surfactant in which the betaine surfactant is mixed with an aqueous solution of the chelating agent in which the pH has been adjusted to a pH below about 3.0, but above the pH at which the free acid of the chelating agent precipitated, and the resulting fluid system was used for both acid fracturing and matrix stimulation, as well as reoperation procedures such as the elimination of scale and filter cake, especially in high temperature formations.