Viscoelastic surfactant fluids at high brine concentrations

Surfactants are viscous and elastic fluids that are stable at high concentrations of salt solutions

Background of the invention

Viscous and elastic surfactant fluids that are stable at high concentrations of brine solutions Background This invention relates to the drilling, completion, and stimulation of hydrocarbon wells and specifically relates to fluids and methods for gravel grouting, cleaning, or drilling in an underground formation. Viscous fluids play several important roles in oilfield maintenance applications, as the viscosity of fluids allows them to carry particles from one formation zone, one wellbore, or one surface equipment to the next. For example, one function of the drilling fluid is to carry drilling bits from around the drill bit out of the wellbore to the surface. Fluid viscosity also plays an important role, for example in laying gravel filling. Gravel grouting mainly consists of placing gravel grout around the perimeter of the wellbore in the middle of the production area to reduce sand production from highly permeable formations.

Suspension properties of solids are also important requirements for fracturing fluids. In order for the well to produce

A hydrocarbon from an underground geological formation, the hydrocarbons must follow an adequately unobstructed flow path from the reservoir to the wellbore. If the formation has low permeability, either naturally or due to formation disruption caused by the addition of process fluids or the formation of crusts, for example, it may break down to increase permeability. Specifically, fracturing involves breaking a portion of the surrounding layer by directing fluid injection to the surface of a geological formation at sufficient pressure to initiate and/or extend a fracture in the formation. The fracture fluid typically includes an element

Support such as ceramic balls or sand to stabilize the fracture opening after stress release and it is therefore important that the fluid has sufficient viscosity to carry the reinforced element to the fracture.

Fluid viscosity is generally obtained by adding water-soluble polymers such as polysaccharide derivatives. Viscoelastic surfactants have been used in the form of texture thickeners. In contrast to polymers, fluids based on viscoelastic surfactants do not reduce permeability as a result of rigid deposits and offer lower frictional pressure. In addition, the fluid viscosity is reduced or lost when exposed to formation fluids such as crude oil to ensure better crack cleaning.

Viscoelastic surfactants are formed by mixing appropriate surfactants such as anionic and cationic surfactants. The viscosity of viscoelastic surfactants is attributed to the three-dimensional structure formed by elements in the fluids. When the concentration of surfactants in a viscoelastic fluid significantly exceeds the critical concentration, often in the presence of an electrolyte, the surfactant atoms accumulate in species such as molecules that may interact to form a network that exhibits elastic behavior. The molecules are used in the remainder of this Description as a general term for organized interacting species, Viscoelastic cationic surfactants—typically a long-chain quaternary ammonium salt such as cetyltrimethylammonium bromide (CTAB)—are of primary commercial interest in wellbore fluid. The general reactants that generate viscosity and elasticity in surfactant solutions are salts such as ammonium chloride, potassium chloride, sodium salicylate, sodium bisuccinate, and non-ionic organic molecules such as chlorine.

Form. The electrolyte content in solutions with reduced surface tension also represents an important control on their viscoelastic behavior. Reference was made, for example, to US Patents Nos. 4,697,389, 4,725,372, 5,551,516, 5,964,295, and 5,979,557. However, fluids containing this type of cationic viscoelastic surfactant lose viscosity at salt concentration. High (10 pounds or more per gallon), these fluids may be specified for use as gravel packing fluids, drilling fluids, or in other applications that require heavy fluids to balance well pressure.

It is also known from International Patent Publication 98/56 497 how to impart viscoelastic properties using amphoteric/dipolar surfactants, an organic acid, a salt and/or an inorganic salt. Surfactants are, for example, dihydroxyl alkylglycinate, alkyl amphoacetate or propionate, alkyl bethane, alkyl amidopropyl bethane, and alkyl amino mono or dipropionate derived from certain wax, grease and oil. Surfactants are used with water-soluble inorganic salts such as aphthalic acid

Salicylic acid or its salts are dual-charged surfactants.

Amphoteric, specifically, those surfactants that include the bethane moiety are valid at temperatures up to about 150°C and are therefore useful for media in high temperature wells. However, it is incompatible with high concentrations of solution

Salt such as cationic viscoelastic surfactants.

The invention provides a viscoelastic fluid that serves as a thickener for suspending particles and specifically as a thickener for wellbore fluids, which maintains viscosity at high brine concentrations. According to the first embodiment, the invention relates to a fluid comprising a carrier fluid with a high brine content having a density of at least 10 pounds per gallon or 1.1 9 8 g/cm and a portion selected from a group consisting of organic acids, salts of organic acids, inorganic salts and a combination of One or more organic acids or salts of an organic acid and an amount of dually charged surfactants represented by this formula.

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Whereas R1 is an alkyl, aryl alkyl, alkoxy alkyl, alkyl amino alkyl, or alkyl amido alkyl, consisting of about 12 to about 42 carbon atoms, and with straight or branched chains, saturated or unsaturated, and R2 and R3 are separately Hydrogen or aliphatic chain with one carbon atom up to about 30 and R4 is a hydrocarbyl moiety containing one carbon atom

One to 4 and a common surfactant.

The surfactant increases the durability of the viscoelastic fluid-based gel, if required. The common surfactant is the alkyl benzene sulfonate salt and the better salts are sodium dodecylbenzenesulfonate (SDBS) and sodium dodecyl sulfonate.

Sulfate (SDS) alkyl phosphonates and alkyl carboxylates may also be used. It is preferable that the concentration of the surfactant involved in the fluid be about 1, wt% up to about 1 wt%, and it is preferable that the concentration of the surfactant in the fluid be about 0.29 wt% up to about 0.5 wt%. The elements of the invention are also compatible with metallic acids. And membership.

According to the second embodiment, the invention relates in particular to a fluid comprising a carrier fluid containing a high-density saline solution (at least 10 pounds per gallon or 1.198 grams/cm3) and a portion selected from a group consisting of organic acids, salts of organic acids, inorganic salts, and a combination of an organic acid or The salt of one or more organic acids and an amount of the dually charged surfactant with the following formula:

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Where R1 is an alkyl, alkyl aryl alkyl, alkoxy alkyl, alkyl amino alkyl, or alkyl amido alkyl, consisting of about 2 1 to about 4 2 carbon atoms, and `chains - or branched, saturated or unsaturated, and R2 and R3 are separately Hydrogen or aliphatic chain with one carbon atom up to about 0 3 and R4 is a hydrocarbyl moiety containing one carbon atom up to 4 and a chelating agent.

Chelating agents are typically hydroxyethyl aminocarboxylic acids. The hydroxyethyl aminocarboxylic acid shall preferably be selected from hydroxyethylenediaminetriacetic acid (HEDTA), hydroxyethyliminodiacetic acid (HEIDA), or a mixture thereof, or the hydroxyalkyl, allyl, or aryl-aminocarboxylic acids of the corresponding materials. Hydroxyethyl aminocarboxylic acid is mainly used to remove drilling fluid deposits from the wellbore. In particular to remove filter cake. It is also used to prevent the precipitation of iron species and remove carbonate and sulfate scales. Ethylenediaminetetra-acetate (EDTA) is not preferred, as this chelating agent tends to reduce the likelihood of forming a viscous gel with the dual-charged surfactants or to produce a gel whose viscosity decreases over time. Hydroxyethylaminocarboxylic acids may be used at room temperature in the presence of SDBS to improve the compatibility of viscoelastic surfactants with the surfactant solution. However, co-surfactants must be omitted at a higher temperature, such as wellbore temperature, if the surfactant solution phase includes hydroxyethyl aminocarboxylic acid, otherwise the gel will spoil.

The carrier fluid is a brine solution, i.e. water containing an inorganic salt or an organic salt. The preferred monovalent inorganic salts include an alkali metal halide, preferably sodium bromide, potassium, or cesium. Sodium bromide is particularly preferred. The surfactant phase of the carrier solution also includes an organic salt, preferably potassium or sodium formate. Divalent inorganic salts include calcium halide, preferably calcium chloride or calcium bromide. Zinc halide, especially zinc bromide, is not preferred, as it has been observed that these salts

Reduces the viscosity of the viscoelastic solution. Salt is chosen for compatibility reasons, i.e. when drilling fluid is used in the tank, a specific brine phase is chosen and a brine phase is chosen for the cleaning/completion fluid as it includes the same brine phase and when hydroxyethyl aminocarboxylic acids are used to clean the wellbore, it is preferable for the surface solution to consist mainly of Monovalent salts where divalent salts are converted into chelating agents to allow less HA for cleaning.

The concentrations of salts in the fluid are at least high enough so that the density of the carrier fluid is at least about 10 pounds per gallon, preferably from about 10 pounds per gallon up to about 15 pounds per gallon. The inorganic salt may be added to the carrier fluid in any hydrogenation state (i.e., anhydrous, monohydrated, dihydrated, etc.). Organic salts such as formate may be added to the composition up to about 9.5 pounds per gallon, above which phase separation may occur. Therefore, some inorganic salts must not be added to obtain a density higher than 10 pounds per gallon. The tolerance of the dual-charged surfactant to electrolysis also allows for formulas that are less than 10 pounds per gallon, where the surfactant phase is chosen so that it is compatible with the surfactant phase of other drilling fluids for completion or reservoir D HCOOK or HCOONa at about 24 wt.% (9.5 pounds per gallon) or less. The surfactant is able to form structures such as colloidal particles that...

It is in the form of a plate, or in a ring, vesicular, or spiral form, and the latter form is preferred. The most preferred dual-charge surfactant includes a betaine moiety and an olepic acid moiety such as the surfactant in 30- O -BET (Rhodia). And it must

Note that the amount of oleic acid from which the oleic acid portion is extracted reached a purity of about 75% to about 85%, and the rest of the amount includes other fatty acids such as linoleic acid, linoleic acid, etc. Some fatty acids may be present in about 15% to 25% of surfactant molecules in place of oleic acid. It is preferable that the concentration of the viscoelastic surfactant in the solution be between about 1 wt% to about 10 wt%, and it is preferable that the concentration be about 2.9 wt% to about 5 wt%.

There may be other components in the fluid, such as scale and corrosion inhibitors or biocides, depending on the purpose for which it is used, conditions of formation, and other variables that are clear to the specialist in this field. For example, when used as a drilling fluid, it is preferable to include surface active agents and materials to add viscosity. Such as polymer, filtration control agents such as Gilsonite, modified starch, thickening agents such as powdered barite, hemamate, powdered calcium carbonate or other wellbore fluid additives known to industry professionals. When used as a gravel filling fluid, it preferably includes gravel and other optional additives such as filter cake cleaning reactants such as the chelating agents indicated above or acid corrosion inhibitors (such as hydrochloric, hydrofluoric, formic, acetic, and citric acids), scale inhibitors, biocides, seepage control agents, among others. . For this application, suitable gravel or sand typically has a mesh size between 8 and 70 according to the American Standard for Screen Size of Mesh Series.

When used as a fracturing fluid, it is preferable to include a supporting element. Suitable supporting elements include, but are not limited to, sand, bauxite, glass balls, and ceramic balls. If sand is used, its size is typically from about 20 to about 100 according to the American mesh size standard. It may be used Mixtures of suitable fortified materials. It may also include a backflow inhibitor for the proppant, for example the proppant may be coated with a resin to allow the proppant particles to bond into a bulk. The concentration of the fortified material may be

In the fracturing fluid any concentration known in the art typically ranges from about 0.5 to 0.5

About 20 pounds of fortifier are added per gallon of clean fluid. In another aspect of the present invention, a wellbore treatment method is presented that includes the step of injecting a high-density brine-bearing fluid that includes a dual-charged surfactant and a co-agent such as a chelating agent. 'Processing' is understood as, for example, drilling, hydraulic fracturing and gravel packing. For drilling, the viscoelastic fluid is injected into the wellbore at a flow rate and pressure sufficient to lubricate the drill bit and carry drill bits to the surface. With regard to hydraulic fracturing, the method includes the step of injecting the viscoelastic fluid composition through the wellbore into the underground formation at a sufficient flow rate and pressure. To produce or expand the fracture in the formation. With respect to placing the gravel grout, the method includes the step of injecting a viscoelastic fluid composition containing gravel into the wellbore at a flow rate and pressure sufficient to place the gravel grout in the wellbore. Preferably, the method is performed in configurations with a temperature lower than about 260 F (126.7 C) and preferably using the known alternate path technique e.g. from US Patent 4,945,991.

Regardless of the purpose for which it is used, the fluid may be prepared at any time prior to use by combining a viscoelastic surfactant, a co-surfactant and/or a chelating agent, and a high-density saline fluid along with any other ingredients. A surfactant may typically be found in an aqueous solution, but may also be presented in any other form. A high-density brine may be prepared by adding an inorganic salt to the carrier fluid at any time before, during, or after adding viscoelastic surfactants to the fluid. Additives may be added to the fluid after it is injected into the wellbore.

The compositions and methods of the invention offer several major advantages over prior fluids and methods. While not adhering to theory, it is known that a combined solvent/surfactant acts to allow VES to maintain viscosity in the presence of high concentrations of organic and inorganic salt. Fluids maintain sufficient viscosity without the common SDBS surfactants if the composition of the fluid includes some chelating agent such as HEDTA or HEIDA. The present invention is easy and relatively inexpensive to manufacture. Brief explanation of the drawings

Figure 1 shows the viscosity as a function of temperature of a test solution consisting of 12 pounds per gallon of calcium bromide brine containing a dual-charged surfactant in the absence of a co-surfactant.

Figure 2 shows the viscosity as a function of temperature of a fluid containing a brine saturated with sodium bromide, a dual-charge surfactant, and a co-surfactant.

Figure 3 shows the viscosity as a function of temperature for fluids containing brines of calcium chloride, a dual-charge surfactant, and a co-surfactant.

Figure 4 shows the viscosity as a function of temperature of fluids containing brines of calcium bromide, a dual-charge surfactant, and a co-surfactant.

Figure 5 shows the viscosity as a function of temperature for fluids containing sodium bromide brine, a dual-charge surfactant, HEDTA as a chelating agent, and optionally a co-surfactant.

Figure 6 shows the viscosity as a function of temperature of the fluid containing the sodium bromide brine, the surfactant, and HEIDA as the chelating agent. Figure 7 shows the viscosity as a function of temperature of a fluid containing a brine solution of calcium bromide, several concentrations of HEDTA as a chelating agent, and several concentrations of a dual-charge surfactant.

Figure 8 shows the viscosity as a function of temperature of a fluid containing several concentrations of HEDTA as a chelating agent with sodium bromide at several concentrations below saturation. Figure 9 shows the leakage volume versus time after cleaning treatment with a fluid according to the invention.

Detailed description

When compositions of the present invention are described as including certain substances, it is understood that the composition may optionally include two or more chemically different substances. Furthermore, the composition may also include some elements not already mentioned. The dual-charged surfactant may be used with other viscoelastic surfactants including ammonium chloride to bis(2-hydroxyethyl)methyl ammonium chloride; Ammonium chloride of trimethyl erucyl; Ammonium chloride for N-methyl-N,N-bis(2-hydroxyethyl) rapeseed;; ammonium chloride of oleylmethyl bis(hydroxyethyl); Ammonium bromide of octadecylmethyl bis(hydroxyethyl), ammonium bromide of octadecyltris(hydroxyethyl); ammonium bromide of octadecyldimethylhydroxyethyl; Cetyldimethylhydroxyethyl ammonium bromide; Ammonium Salicylate for Cetyl Methyl Bis(Hydroxyethyl), Cypyl Methyl Bis(Hydroxyethyl) Ammonium 3,4-Dichlorobenzoate; Tris(hydroxyethyl) ammonium iodide; Aminobis (hydroxyethyl) soy; N-methyl, amine N-hydroxyethyl animal tallow, bis(hydroxyethyl)octadecyl amine; Dimethylhydroxyethyl ammonium bromide; Ammonium chloride for Kozel

Methyl Bis (hydroxyethyl); Cosylmethyl bis(hydroxyethyl) ammonium bromide;

ammonium bromide for dicosyldimethylhydroxyethyl; Ammonium chloride for dicosylmethyl bis

(Hydroxyethyl); Dicosyltris(hydroxyethyl) ammonium bromide; Ammonium chloride

Hexadecyl Ethyl Bis(Hydroxyethyl), Ammonium Iodide for Hexadecyl Isopropyl Bis(Hydroxyethyl); N-amine, N-dihydroxypropyl hexadecyl, N-methyl, N-amine

Hydroxyethyl hexadecyl, N-amine, N-dihydroxyethyl dihydroxypropyloleyl,

N,N-dihydroxypropyl soy amine; amine N,N-dihydroxypropyl animal fat; N-butyl hexadecyl amine; N-hydroxyethyl octadecyl amine; amine N-hydroxyethylcosyl; Cetyl Amino, N-Oxtadecylpyridinium Chloride, N-Soy-N-Ethyl Morpholinium Ethosulfate; Methyl sulfate of methyl-1-oleyl amidoethyl-2-oleylimidazolinium; and methyl sulfate of methyl-1-amidoethyl tallow-2-imidazolinium

Animal fat.

The fracturing fluid may also include a cutting material. The purpose of this element is to 'cut' or reduce the viscosity of the fracturing fluid, so that this fluid is more easily recovered from the fracture during clean-up. Typical cutting materials include citric acid as stated in US Patent Application 9/826,127. Filed on April 4, 2001, and mentioned below by reference. The fluid may also include one or more additional substances such as surfactants, cutter auxiliaries, salts (such as potassium chloride), anti-foam agents, scale inhibitors, and bactericides. The fracturing fluid may also optionally contain materials intended to divert the backflow of the proppant after completion of the crushing process by forming a porous pack in the fracturing zone. These materials, hereinafter called "backflow inhibitors of the proppant" may be any material known in the art. Such as those available at Schlumberger under the trade name PropnetTM.

In another embodiment, the present invention relates to a method for hydraulically breaking up an underground formation. Hydraulic fracturing techniques for underground formation are known to specialists in this field.

It involves pumping fracturing fluid into the wellbore and out into the surrounding formation. The fluid pressure is higher than the minimum pressure of the rock in situ, thus causing fractures or extending them in the formation Stimulation Engineering Handbook, John w. Ely, Pennwell Publishing Co., Tulsa, see

Okla. (1994)

In another embodiment, the present invention relates to a method for making a wellbore. The method includes introducing wellbore completion fluid as mentioned above, injecting the fluid into a fresh wellbore in which the drill bit is operating, and removing drilling debris from around the drill bit using the wellbore completion fluid. In another embodiment, the present invention relates to a method for making a gravel filling in a well pit. Gravel packing is typically only used in unconsolidated formations, which tends to produce an undesirable high level of particles with the formation fluids. The method includes placing a solution containing an amount of gravel and/or sand with a mesh size between 8 and 70 according to the American standard mesh size series in a formation adjacent to the wellbore. It is sometimes preferable to bind gravel particles together to form a porous matrix for the passage of formation fluids while facilitating the filtration and retention in the well of the unconsolidated mass of sand and/or fine sediments in the well that are transported to an area adjacent to the wellbore by formation fluids or hydrocarbon (gas). The gravel particles may form resin-coated gravel, which is either pre-treated or may be treated with a flow of chemical binding agents while the gravel is in place. In some cases, various binding agents have been used on the gravel particles in order to bind them together to form a porous matrix. The gravel or sand is placed in formations adjacent to the wellbore by injecting a fluid according to the present invention and the gravel and sand into the wellbore. The fluids of the invention are optionally removed from the gravel or sand in place.

The fluids were prepared to include bethanoleic acid, a product obtained in the form of BET-O-30 from Rhodia Inc., USA as a dual-charge viscoelastic surfactant. BET-O-30 is an aqueous solution containing 29% bethane-oleic acid (oleic amidopropylbethane) surfactant, 17% propylene glycol, and 48.5% water. A solution is prepared in a calcium bromide salt solution (12 pounds per gallon) with 10% -BET-O 30 (all proportions are volume ratios unless specified). Therefore, the concentration of the viscoelastic surfactant bethanoleic acid is 2.9%. The pH is adjusted using concentrated acid chloride. The fluid viscosity is recorded using a 50 Fann rotary cylinder viscometer.

Figure 1 shows the resulting viscosity in centipoise [CP] at a shear rate of 100 s1 - as a function of temperature at the range from 70 to 270 F (from about 21 C to about 130 C) for fluids that include water with a brine solution of calcium bromide and the surfactant bethane. - Oleic, for different values of pH. The results show that there is virtually no increase in viscosity.

In a similar manner, the fluid is prepared based on a sodium bromide brine saturated with salt with 10% BET-O-30 plus 0.3% SDBS in an aqueous solution with a density of 12.7 pounds per gallon. The test solution does not undergo phase separation at saturated sodium bromide brine concentrations. The solution is shaken, then the shaking stops, and Figure 2 shows the viscosity at 170 seconds1- as a function of temperature at the same temperature rate. The results show that it is

It is possible to obtain a gel using charged dual surfactants, combined surfactants and high density brine. Similar examinations were performed with divalent salt solutions. Figure 3 shows the viscosity as a function of temperature for the test solutions, which consisted of calcium chloride brine with 10% BET-O-30 and 0.3% SDBS. One test solution consists of 48% CaCl2 (obliterated diamond shape) and the other is 80% CaCl2 (10.74 lb/gal) (open squares). The viscosity of the test solution containing 80% CaCl2 is approximately 2 to 3 times higher than the viscosity of the test solution with lower concentrations of calcium chloride at temperatures greater than

About 120 F to about 260 F.

Figure 4 shows the viscosity as a function of temperature of similar solutions weighed with calcium bromide. The blurred circle marks represent a solution with 60% CaBr2, with a density of 11.5 lb/gal (1.378 g/cm3). The open squares represent the solution with 100% CaBr2, with a density of 12.98 lb/gal (1.555 g/cm3), and the viscosity of the two models is approximately constant at about 130 at 100 seconds1 - under a temperature of about 220 F (1.4 C). Furthermore, in order to verify that the test solution will undergo phase separation at very high brine concentrations, a test solution is prepared with 160% CaBr2 [pressure = 79.1 g/cm3 at room temperature 14.94 lb/gal]. . The solution is shaken, then the shaking is stopped. No phase separation is evident in the resulting mixture after about 2 to 3 days at room temperature, even though the viscosity of the solution is relatively low.

Additional fluids are prepared to check the compatibility of the monovalent viscoelastic salt solution with the chelating agent. Figure 5 shows the viscosity for 170 seconds as a function of the temperature of the fluids weighed with sodium bromide brine to obtain a density of 12.7 lb/gallon (1.521 g/cm3). The fluids include 10% BET-O-30, 0.2% corrosion inhibitor, and a 40% chelating agent solution including 50% by weight HEDTA in water. The pH of the brine is lowered to 4 by adding chloric acid. To one fluid (blurred circles) 0.3% SDBS is added, while the other fluid (open triangle) does not contain SDBS. This examination demonstrates that monovalent brines according to the invention are compatible with chelating agents, and indeed that chelating agents should not be used with common surfactants at wellbore temperatures.

Similar results are obtained with HEIDA as a chelating agent. Figure 6 shows the viscosity at 170 s1 as a function of temperature of a fluid containing 10% 30-BET-O, weighing 11.6 pounds per gallon with sodium bromide brine and a 30% chelating agent solution consisting of a solution at 50% HEIDA in water. The pH decreases to 7 with chloric acid.

As shown in Figure 7, the use of a chelating agent enhances compatibility with divalent saline. Fluids containing 5% (obliterated marks) or 10% (open marks) BET-O 30 with calcium bromide are weighed so that the density of the fluid is 13.7 lb/gal (1,641 g/cm3). 25% (triangles) and 40% (circles) of a 50% HEDTA solution are added and the pH is reduced to 2 by acid chloride.

Additional fluids are prepared to demonstrate that less than saturated sodium bromide salt concentrations are compatible and that a viscous solution suitable for use is produced. Figure 8 shows the viscosity at 170 seconds1 - as a function of the temperature of the fluids weighed with sodium bromide brine, several concentrations of the chelating agent solution CAS (a solution containing 50% by weight of HEDTA in water) and 10% 30-BET-O at pH Reduced to pH 4.5 by acid chloride.

Figure 9 shows the time required for the fluid containing the chelating agent (10% 30-BET-O and HEDTA at pH 4.5) to decompose the filtration paste of an oil-based synthetic tank drilling fluid, which appears in a 500 mD berea sandstone core at 175 F (79.4 m) and 300 psi (2.068 MPa) for 16 hours. Solutions of the chelating agent are formed in a viscoelastic surfactant gel. The viscosity cleaning treatment is used in a 20/40 mesh sand gravel fill at 300 psi for loss of balance and at 175 F. The treatment fluid is a stone filling fluid containing BET O-30 with HEDTA.

The foregoing description of specific embodiments of the invention is not intended to represent a complete list of all possible embodiments of the invention. Experts in this field realize that modifications may be made in the specific embodiments described, but they are within the scope of the present invention.