CA1086637A - Method for generating hydrofluoric acid in a subterranean formation - Google Patents
Method for generating hydrofluoric acid in a subterranean formationInfo
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- CA1086637A CA1086637A CA314,190A CA314190A CA1086637A CA 1086637 A CA1086637 A CA 1086637A CA 314190 A CA314190 A CA 314190A CA 1086637 A CA1086637 A CA 1086637A
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Abstract
ABSTRACT
A method is disclosed for generating or forming hydrofluoric acid in a subterranean siliceous formation by combining an injected aqueous solution of a fluoride salt and an injected aqueous acid solu-tion in the pore spaces of the formation. This is accomplished according to this invention by immobilizing one of the aqueous solutions in the pore spaces of the formation by displacing the aqueous solution into the formation with a liquid that is substantially immiscible with the injected aqueous solution, thereby driving said aqueous solution to a saturation at or below its residual saturation. The other aqueous solution is then injected into the formation.
A method is disclosed for generating or forming hydrofluoric acid in a subterranean siliceous formation by combining an injected aqueous solution of a fluoride salt and an injected aqueous acid solu-tion in the pore spaces of the formation. This is accomplished according to this invention by immobilizing one of the aqueous solutions in the pore spaces of the formation by displacing the aqueous solution into the formation with a liquid that is substantially immiscible with the injected aqueous solution, thereby driving said aqueous solution to a saturation at or below its residual saturation. The other aqueous solution is then injected into the formation.
Description
~86637 1 BACXGROU~D ~ THE I~ TION
2 1. Field of the Invention
3 ` The present invention relates to the treatment of subterranean
4 formations penetrated by wellbores, and relates more particularly to methods for treatment of subterranean siliceous formations with acid.
6 2. Prior Art 7 Often the cause of low productivity of oil and gas in sub-8 terranean sandstone formations is reduc~d formation permeability near 9 the wellbore. This condition, called "formation damage" has been related to a variety of completion and drilling practices. For example, 11 the perforating of casing may reduce permeability around the perforation 12 by matrix crushing and compaction caused by the shaped charge or by gun 13 debris. The loss of completion fluids, filtrates from drilling mud, or 14 drilling mud particles may cause clay swelling, particle plugging by dispersed formation fines, particle invasion, or adverse change in fluid 16 saturation.
17 Many of the adverse permeability effects relate directly to 18 the clay fraction of the matrix. It is well known that certain effects 19 such as clay swelling, clay dispersion, and particle plugging can be reduced by solubilizing the clay with mineral acid solutions of hydrogen 21 fluoride. Commonly, aqueous solutions containing from about 2 to 6 22 weight percent hydrofluoric acid and from 5 to 15 weight percent hydro-23 chloric acid (generally called "Mud Acid") are employed to treat the 24 damaged formations. The low pH conditions provided by the hydrochloric acid is beneficial in solubilizing the products formed by the reaction 26 between hydrofluoric and the formation material. This HF-HC1 treating 27 solution .eacts most rapidly with calcite, rapidly with clay, less 28 rapidly with other silicates, and slowest with the silica of natural 29 sands. The precise rates of these reactions are largely controlled by : :' :- :' : : . :
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1~6637 1 the concentration of hydrofluoric acid in ~he treating solution. The 2 higher the hydrofluoric acid concentration the more rapid the reaction 3 rate.
4 Because the reaction of hydrofluoric acid on silica and clay is generally rapid at formation temperatures (120-220F), a majority of 6 the acid solution becomes spent within a radius of about 24 inches from 7 the wellbore and a lesser amount of active acid solution penetrates 8 beyond this distance. Moreover, because the majority of the reaction 9 occurs within a small volume of the formation matrix, the concentration of reaction products (some of which may precipitate) and fines liberated 11 by the reaction may cause permeability impairment if the hydrofluoric 12 acid concentration is too high.
13 Because the materials plugging the porous formation of rock 14 are only removed for a short distance around the well, invasion of the treated region by new fine particles can occur after a short period of 16 time. These fine particles are believed to originate deeper in the 17 formation and are carried toward the wellbore by the flowing fluid 18 during production. A method for achieving deeper acid penetration would 19 remove these particles to a greater radius from the wellbore, thereby lengthening the time required for fines to migrate back to the well.
21 Localized spending of hydrofluoric acid near the wellbore may 22 also result in increased water production. Hydrofluoric acid injected 23 into the wellbore reacts readily at the interface between the formation 24 rock and the cement used to set the wellbore casing. A channel may be formed along this interface which can allow water from the nearby strata 26 to reach the producing well. Elimination of this problem requires that 27 the concentration of hydrofluoric acid in solution be low as fluids are 28 injected into the formation past the formation-cement interface.
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;637 1 A plastic consolidation of incompetent sands is strongly 2 effected by the quality of any preceding acid treatment. The compressive 3 strength of a plastic consolidation decreases as the clay content of the 4 sand increases. It is observed that the strength profile of the consoli-
6 2. Prior Art 7 Often the cause of low productivity of oil and gas in sub-8 terranean sandstone formations is reduc~d formation permeability near 9 the wellbore. This condition, called "formation damage" has been related to a variety of completion and drilling practices. For example, 11 the perforating of casing may reduce permeability around the perforation 12 by matrix crushing and compaction caused by the shaped charge or by gun 13 debris. The loss of completion fluids, filtrates from drilling mud, or 14 drilling mud particles may cause clay swelling, particle plugging by dispersed formation fines, particle invasion, or adverse change in fluid 16 saturation.
17 Many of the adverse permeability effects relate directly to 18 the clay fraction of the matrix. It is well known that certain effects 19 such as clay swelling, clay dispersion, and particle plugging can be reduced by solubilizing the clay with mineral acid solutions of hydrogen 21 fluoride. Commonly, aqueous solutions containing from about 2 to 6 22 weight percent hydrofluoric acid and from 5 to 15 weight percent hydro-23 chloric acid (generally called "Mud Acid") are employed to treat the 24 damaged formations. The low pH conditions provided by the hydrochloric acid is beneficial in solubilizing the products formed by the reaction 26 between hydrofluoric and the formation material. This HF-HC1 treating 27 solution .eacts most rapidly with calcite, rapidly with clay, less 28 rapidly with other silicates, and slowest with the silica of natural 29 sands. The precise rates of these reactions are largely controlled by : :' :- :' : : . :
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1~6637 1 the concentration of hydrofluoric acid in ~he treating solution. The 2 higher the hydrofluoric acid concentration the more rapid the reaction 3 rate.
4 Because the reaction of hydrofluoric acid on silica and clay is generally rapid at formation temperatures (120-220F), a majority of 6 the acid solution becomes spent within a radius of about 24 inches from 7 the wellbore and a lesser amount of active acid solution penetrates 8 beyond this distance. Moreover, because the majority of the reaction 9 occurs within a small volume of the formation matrix, the concentration of reaction products (some of which may precipitate) and fines liberated 11 by the reaction may cause permeability impairment if the hydrofluoric 12 acid concentration is too high.
13 Because the materials plugging the porous formation of rock 14 are only removed for a short distance around the well, invasion of the treated region by new fine particles can occur after a short period of 16 time. These fine particles are believed to originate deeper in the 17 formation and are carried toward the wellbore by the flowing fluid 18 during production. A method for achieving deeper acid penetration would 19 remove these particles to a greater radius from the wellbore, thereby lengthening the time required for fines to migrate back to the well.
21 Localized spending of hydrofluoric acid near the wellbore may 22 also result in increased water production. Hydrofluoric acid injected 23 into the wellbore reacts readily at the interface between the formation 24 rock and the cement used to set the wellbore casing. A channel may be formed along this interface which can allow water from the nearby strata 26 to reach the producing well. Elimination of this problem requires that 27 the concentration of hydrofluoric acid in solution be low as fluids are 28 injected into the formation past the formation-cement interface.
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;637 1 A plastic consolidation of incompetent sands is strongly 2 effected by the quality of any preceding acid treatment. The compressive 3 strength of a plastic consolidation decreases as the clay content of the 4 sand increases. It is observed that the strength profile of the consoli-
5 dation parallels the clay removal profile by the acid. To have high
6 consolidation strengths over the formation volume to be consolidated,
7 clay should be thoroughly and evenly removed from that volume.
8 Numerous procedures have been suggested to obtain substantial
9 penetration of hydrofluoric acid into the formation. One method comprises
10 contacting an oil-containing sandstone formation with a surface-active
11 compound to render the surfaces of the formation sands oil-wet, thereby
12 imparting hydrophobic properties to the formation. As a result of the
13 formation having hydrophobic properties, the reaction rate of hydrofluoric
14 acid within the formation is retarded, thereby enhancing acid penetration
15 into the formation.
16 Another method, as described in U.S. 3,828,854, issued to
17 Templeton et al on August 13, 1974, generates hydrofluoric acid in situ.
18 In this method, an aqueous solution of a water soluble fluoride salt is 3
19 mixed with a relatively slowly-reactive acid-yielding material that
20 subsequently converts the fluoride salt solution to a hydrofluoric acid
21 solution that has a relatively high pH (at least about 2), but is capable
22 of dissolving siliceous materials. In the preferred embodiment, the
23 fluoride salt is an ammonium salt of hydrofluoric acid and the acid-
24 yielding material is a formic acid ester. One problem with this method
25 is that the formic acid formed from the ester hydrolysis is a weak acid
26 so that the pH of the treating solution formed is relatively high. In
27 this relatively high pH solution, the hydrofluoric acid concentration is
28 relatively low so that the rate and the extent of the reaction with the ... .:, ;.
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1 formation matrix is consequently low. For any fluoride ion concentration, 2 the pH should be reduced to at least about 1 to maximize hydrofluoric 3 acid generation from fluoride ion and to effectively solubilize reaction 4 products. This process is further limited by the solubility of the formic acid ester in ammonium fluoride solutions. The total amount of 6 hydrofluoric acid which can be formed by this process is limited by the 7 amounts of formic acid and ammonium fluoride which can be combined in 8 solution.
9 Another hydrofluoric acid generation method (as described in SPE Paper No. 6512 entitled "A New Technique for Generating In-Situ 11 Hydrofluoric Acid for Deep Clay Damage Removal" by B. E. Hall, presented 12 at the 47th Annual California Regional Meeting of the SPE on April 13-13 15, 1977) is multi sequential injection of fluoride ion solution followed 14 by a hydrochloric acid solution. The beneficial effect of this pro-cedure is ascribed to the adsorption of fluoride ions on the anion 16 exchange sites of the clay minerals followed by activation of the 17 adsorbed fluoride ions by a pursuing hydrochloric acid solution. The 18 effectiveness of this process is limited by the anion exchange capacity 19 of the resident clay. Since most clays have a small anion exchange capacity, the amount of hydrogen fluoride produced by this method is 21 also small.
22 A need still exists for an improved technique for generating 23 hydrofluoric acid in a formation which overcomes the problems associated 24 with rapid spending of the acid solution within a short radial distance from the wellbore.
27 In accordance with the present invention, the hydrofluoric 28 acid is formed by combining an aqueous solution of a fluoride salt and
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1 formation matrix is consequently low. For any fluoride ion concentration, 2 the pH should be reduced to at least about 1 to maximize hydrofluoric 3 acid generation from fluoride ion and to effectively solubilize reaction 4 products. This process is further limited by the solubility of the formic acid ester in ammonium fluoride solutions. The total amount of 6 hydrofluoric acid which can be formed by this process is limited by the 7 amounts of formic acid and ammonium fluoride which can be combined in 8 solution.
9 Another hydrofluoric acid generation method (as described in SPE Paper No. 6512 entitled "A New Technique for Generating In-Situ 11 Hydrofluoric Acid for Deep Clay Damage Removal" by B. E. Hall, presented 12 at the 47th Annual California Regional Meeting of the SPE on April 13-13 15, 1977) is multi sequential injection of fluoride ion solution followed 14 by a hydrochloric acid solution. The beneficial effect of this pro-cedure is ascribed to the adsorption of fluoride ions on the anion 16 exchange sites of the clay minerals followed by activation of the 17 adsorbed fluoride ions by a pursuing hydrochloric acid solution. The 18 effectiveness of this process is limited by the anion exchange capacity 19 of the resident clay. Since most clays have a small anion exchange capacity, the amount of hydrogen fluoride produced by this method is 21 also small.
22 A need still exists for an improved technique for generating 23 hydrofluoric acid in a formation which overcomes the problems associated 24 with rapid spending of the acid solution within a short radial distance from the wellbore.
27 In accordance with the present invention, the hydrofluoric 28 acid is formed by combining an aqueous solution of a fluoride salt and
29 an aqueous solution of an acid in the pore spaces O r the formation.
This is accomplished by immobilizing one of the aqueous solutions, in 31 the pore spaces of the formation by displacing solution with a liquid 1~86637 .
phase that is substantially immiscible with said aqueous phase, thereby driving said aqueous solution to a saturation at or below its residual saturation. The second aqueous solution is then injected into the formation.
More particularly, the present invention provides a method for acidizing a subterranean siliceous formation surrounding a wellbore wherein at least two aqueous solutions are injected into the formation, one of the aqueous solutions containing a fluoride salt and the other aqueous solution containing an acid, the improvement comprising the steps of ~ (a) injecting into the formation one of said aqueous solutions, (b) injecting into the formation a liquid that is substantially immiscible with said injected aqueous solution in an amount sufficient to substantially reduce the saturation of the injected aqueous solution in a substantial portion of the formation invaded by said aqueous solution in step (a); and - (c) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
In a preferred embodiment, water containing an ammonium salt of hydrofluoric acid is injected into the formation to be treated. The salt solution is then followed by a hydrocarbon liquid such as diesel oil to reduce the saturation of the salt solution to residual saturation. After the hydrocarbon liquid has been injected, hydrochloric acid solution is injected into the formation. The acid solution contacts the ammonium fluoride salts to form hydrofluoric acid which is capable of dissolving siliceous material in the formation.
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Other embodiments of this invention include adding various additives such as viscosifiers, surface active compounds and corrosion - inhibitors to the aqueous fluoride-containing solution and/or the injected hydrocarbon liquid and/or the aqueous acid-containing solution.
It is particularly preferred in the practice of this invention to inject into the formation an aqueous fluoride-containing solution which also contains a viscosifier such as a salt of poly 2-acrylamido-2-methyl propyl sulfonate and to inject into the formation a hydrocarbon which also contains one or more preferentially oil soluble surface-active compounds such as ethylene glycol monobutyl ether and/or sorbitan monooleate It is also particularly preferred in the practice of this invention to follow the aqueous fluoride containing solution with two sequential volumes of diesel oil; the first volume containing surface active compounds and the second volume being substantially free of surface-active compounds.
The practice of this invention provides an improved process for generating hydrofluoric acid in a formation. By this process, -6a-- : .. :- ,.
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1(~86637 1 hydrofluoric acid is continuously generated at and behind the advancing 2 hydrochloric acid front as it displaces the hydrocarbon liquid which 3 immobilized the fluoride salt solution from the pore spaces. In this 4 way hydrofluoric acid is generated at deeper radial depths into the formation than practicable prior to this invention. This invention sub-6 stantially alleviates the problems associated with rapid spending of 7 hydrofluoric acid within a short radial distance from the wellbore.
9 FIGURES 1 A-E are graphic illustrations of a formation showing the percentage saturations of fluids in the formation at various stages 11 in the processes of this invention.
12 FIGURE l-A shows the formation oil and water saturations prior 13 to the practice of this invention.
14 FIGURE l-B shows the formation fluids saturations as an aqueous fluid containing fluoride salts is injected into the formation.
16 FIGURE l-C shows the formation fluid saturations as a hydro-17 carbon fluid such as diesel oil is injected into the formation.
18 FIGURE l-D shows the formation fluid saturations wherein the 19 oil has reduced the saturation of the fluoride-containing fluid tG
residual saturation.
21 FIGURE l-E shows the formation fluid saturations as an aqueous 22 solution containing an acid is injected into the formation.
23 FIGURE 2 is a graph of laboratory tests on several sand samples 24 showing the relation between clay content in percent and distance in inches from the ends of the samples into which fluids were injected.
26 The results illustrated in this FIGURE show the improvement of the 27 present invention over several prior ar-t processes.
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1~86637 1 DESCRIPTION OF THE PREFERRED EMBODI~IENTS
2 The present invention is particularly useful for treating a 3 subterranean sandstone formation to improve effective permeability by 4 dissolving siliceous materials. These materials may comprise fine particles of sand, clay, silica or other silicate minerals, as well as 6 intergranular cementing material in the pores of a subterranean formation, 7 or a sand or gravel pack in the borehole of the well.
8 The present invention is an improved technique for generating - 9 hydrogen fluoride in a subterranean sandstone formation. In a preferred embodiment of this invention fluoride ion-containing salt solution is 11 injected into the formation and then immobilized in the pore spaces of 12 the formation by injection of a hydrocarbon liquid. An aqueous solution 13 containing an acid is then injected into this formation to generate 14 hydrofluoric acid. The method effectively produces hydrofluoric acid uniformly over the entire region containing immobile fluoride compounds.
16 Substantial penetration of the formation can therefore be achieved with 17 the active acid solution of hydrochloric and hydrofluoric acids.
18 The practice of a preferred embodiment of this invention may 19 be explained more clearly by referring to FIGS. lA, B, C, D, and E.
FIGURE l-A illustrates the oil and brine saturation in the subterranean 21 formation prior to the practice of this invention. In this portion of 22 the formation, the oil saturation is considered to be at residual oil 23 saturation. This condition which will exist after brine is injected 24 into an oil-bearing reservoir. FIGS. l B-E show the formation fluid saturations as the formation is being flooded with fluids in accordance 26 with this invention. Advancing fluid fronts are shown by vertical 27 lines, but it is understood that such interfaces are usually irregular 28 and are not well defined.
1 The first step in this embodiment is to inject into the forma-2 tion by means of a well an aqueous solution containing a fluoride salt.
3 As shown in FIGURE l-B, the fluoride-containing solution drives the 4 brine away from the wellbore and bypasses the residual oil in the forma-tion pore spaces. After a suitable amount of the aqueous liquid has 6 been injected, a hydrocarbon solution such as diesel oil is injected 7 into the formation. As shown in FIGURE l-C, the injected oil drives the 8 mobile aqueous fluoride-containing solution away from the wellbore 9 leaving an immobile residual saturation of the fluoride-containing solution. If a sufficient amount of oil is injected into the formation, 11 the oil will reduce essentially all the fluoride-containing solution to 12 its residual saturation (as depicted in FIG. l-D). By definition when 13 the fluoride-containing solution is at or below its residual saturation, 14 it cannot flow (it is immobiliæed) as oil phase flows through the pore space around it. After a suitable amount of hydrocarbon has been injected, 16 an aqueous solution containing an acid is injected in the formation.
17 The acid solution drives the mobile hydrocarbon away from the wellbore, 18 replaces the displaced oil with aqueous acid and reduces the oil satura-19 tion in the formation to its residual saturation. The aqueous fluoride-containing solution is not displaced ahead of the acid solution. Rather, 21 the acid solution mixes with the previously residual fluoride ion-22 containing solution as it is encountered to continuously form hydrogen 23 fluoride at the advancing acid front. The generation of hydrogen fluoride24 continues for some distance behind the acid front as fluoride ions diffuse out of the smaller pore spaces and acid diffuses into them. The 26 hydrogen fluoride thus generated can dissolve siliceous materials in the 27 formation. Since the clay minerals react with hydrogen fluoride several 28 orders of magnitude faster than other siliceous materials, clay is 29 preferentially removed.
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~0~36637 1 The aqueous fluid containing fluoride salt is preferably 2 formed from water which is substantially free of metal ions because many 3 metal ions complex or precipitate fluoride ions or reaction products 4 thereof.
The amount of fluoride-containing fluid injected will vary 6 depending on the extent of formation damage, the formation porosity, and 7 the permeability of the formation to flow of aqueous fluoride-containing 8 solution. Generally about l barrel to about 20 barrels of liquid are 9 injected per foot of formation interval to be treated.
The water-soluble fluoride salts used in the present invention 11 can comprise one or more of substantially any fluoride salt that is 12 water soluble. Ammonium salts of hydrofluoric acid, i.e. ammonium 13 fluoride or ammonium bifluoride, are preferred fluoride salts for use in 14 the present process. In using ammonium bifluoride (NH4HF2) it may be desirable to add enough ammonia or ammonium hydroxide to provide sub-16 stantially equimolar amounts of ammonium and fluoride ions.
17 The concentration of fluoride salt in the aqueous solution can 18 vary widely depending on the degree of damage to be removed and porosity 19 of the formation. As is well known, the amount of siliceous material that will be dissolved can be increased by increasing the concentration 21 of the hydrofluoric acid. Therefore, it is generally preferred to 22 contact the siliceous material with a strong solution. In many prior 23 art processes, strong HF solutions cause permeability damage due to 24 reaction generated pricipitates and fines. For example, permeability damage frequently occurs when a high HF concentration is injected at the 26 formation face because a majority of the reaction with the formation 27 matrix occurs in the small formation volume near the face. In the 28 present invention permeability damage is alleviated because hydrogen 29 fluoride is generated over the entire region containing fluoride salts so that the concentration of reaction generated precipitates and fines 31 remains low and uniformly distributed.
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108~637 1 The liquid injected into the formation after injection of the 2 aqueous liquid-containing fluoride salts may be any liquid which is 3 substantially immiscible with the aqueous fluoride-containing solution 4 and will immiscibly displace aqueous liquids in a porous medium. Examples of suitable liquids include perflurohexane, perflurooctane, cyclohexanone, 6 dioctyl ether, decanol, and hydrocarbons including kerosene, light 7 crude oil, diesel oil, and xylene. For economic reasons, the aqueous 8 immiscible liquid will most frequently be a hydrocarbon. The use of 9 diesel fuel or similar low viscosity petroleum fraction is generally preferred.
11 The amount of hydrocarbon or other liquid immiscible with the 12 aqueous solution injected into the formation will vary depending on the 13 amount of fluoride-containing solution injected into the formation.
14 Preferably, a sufficient volume of liquid is injected to reduce sub~
stantially all of the fluoride-containing solution to residual fluid 16 saturation. Generally the volume of injected hydrocarbon will be about 17 the same as the volume of the injected aqueous solution containing 18 fluoride salts.
19 In the most preferred embodiment, two hydrocarbon-volumes will be injected sequentially. In this embodiment, the first volume will 21 contain a low molecular weight preferentially oil soluble surface-active 22 agent such as ethylene glycol monobutyl ether and/or a higher molecular 23 weight preferentially oil soluble surface-active agent such as sorbitan 24 monooleate. The second volume will contain no surface active agent.
The object of this two-volume sequence is to reduce the fluoride salt 26 containing solution to a saturation substantially below the residual 27 satuation obtainable with the untreated hydrocarbon fluid. This lower 28 saturation will further assure immobilization of the fluoride solution 29 after injection of the untreated hydrocarbon fluid and will minimize the volume of any subsequent mixing zone between fluoride solution and , . . ;. - : .
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. .: .: : ., : :. ~ i ~086637 1 pursuing acid solution. Each hydrocarbon volume may be about the same 2 as the volume of injected aqueous fluoride solution.
3 Any water soluble acid generally employed in acidizing treat-4 ments may be utilized in the practice of this invention. Suitable acids include, for example, halogen acids such as HCl, HI, and HBr; mineral 6 acids such as sulfuric, nitric, and phosphoric; organic acids such as 7 acetic, proponic acid, and formic acid; modified organic acids such as 8 mono-, di-, and trichloroacetic acids; and, various mixtures thereof.
9 Hydrochloric acid (HCl) is generally preferred. The acid solution can contain up to about 38% by weight of these acids.
11 Viscosity increasing agents may be added to any of the injected 12 fluids in the practice of this invention. Preferably the aqueous fluoride-13 containing solution has a higher viscosity than the injected hydrocarbon 14 fluid and this hydrocarbon fluid preferably has a higher viscosity than the aqueous solution containing acid. This viscosity relationship 16 allows the fluoride-containing solution to efficiently displace the 17 resident aqueous fluids from the pore space. It also reduces fluoride 18 displacement by the aqueous solution containing acid. A suitable visco-19 sifier for use in the aqueous fluoride-containing solution may include a salt of poly-2-acrylamido-2-methyl propyl sulfonate, or other polymeric 21 sulfonate salt.
22 A sufficient amount of acid is preferably injected into the 23 formation to react with all of the fluoride salts injected in the forma 24 tion. It is particularly preferred to inject acid in a significant stoichiometric excess relative to the amount of the fluoride salts in 26 the formation. High concentrations of acid are preferred so as to 27 maximize the concentration of hydrofluoric acid formed at the acid front 28 as it displaces the hydrocarbon bank and assure penetration into the 29 formation of hydrochloric acid to the same radial extent to which the fluoride salt solution has been immobilized. Acid concentrations in 31 excess of 2 molar are preferred.
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~L08~63~7 1 Various additives such as corrosion inhibitors, demulsifying 2 agents, surfactants, and viscosifiers, may be added to the aqueous fluid 3 containing fluoride salts, to the hydrocarbon fluid and/or the acid 4 solution. Suitable inhibltors include the inorganic arsenic compounds, acetylenic alcohols, thiophenols, quaternary ammonia compounds and 6 similar organic agents. Almost any of the surfactants capable of reducing 7 interfacial tension between oil and water may be used in this invention.
8 The surface-active agents selected, of course, should be compatible with 9 the injected hydrocarbon, the fluoride salts, and the acid solution. In the preferred case, they should be preferentially oil soluble and be 11 placed in the injected hydrocarbon. Specific surface active materials 12 which may be employed include, for example, ethylene glycol monobutyl 13 ether and sorbitan monooleate.
14 In performing the matrix acidizing treatment in accordance with this invention, it is desirable to inject all fluids without 16 fracturing the formation. The formation fracture pressure can be de-17 termined by conventional computation techniques employing known or 18 estimated properties of the formation. This pressure limitation de-19 termines the rate at which the acid solution can be injected. Normally from l to 20 barrels of fluoride salt solution per foot of formation, 21 internal to be treated is injected at a rate ranging between about 0.25 22 barrels to 5 barrels per minute.
23 Another embodiment of the present invention is to inject into 24 the formation by means of a well an aqueous solution containing an acid preferably hydrochloric acid. This acid solution is then immobilized by 26 injecting into the formation a liquid, preferably a hydrocarbon, which 27 is substantially immiscible with the acid solution. An aqueous solution 28 containing a fluoride salt, preferably an ammonium salt of hydrofluoric 29 acid, is then injected into the formation. The fluoride salt will contact the acid to form hydrofluoric acid.
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1 A further embodimen. of this invention is to inject a liquid 2 preflush into the formation prior to injection of the fluoride-3 containing solution. In this embodiment an acid solution is injected 4 into the formation. This acid may be intended to react with calcite and other carbonate materials in the formation and thus alleviate undesirable 6 dissipation of the hydrogen fluoride generated at a later stage of the 7 process. In this case the acid solution is preferably hydrochloric 8 acid. The acid so]ution may also be intended to break down the perfora-9 tions in the casing and thereby establish good communication between the well bore and the siliceous formation. In this case the acid solution 11 is preferably a mixture of hydrochloric and hydrGfluoric acids known as 12 mud acid. This acid solution should then be followed with an aqueous 13 solution, preferably an ammonium chloride solution, neutralized with 14 ammonium hydroxide, or ammonium carbonate or ammonium bicarbonate. This aqueous solution serves to displace acid from the formation pore space 16 to be treated so as to prevent premature activation of the fluoride ion 17 containing solution of this invention which may limit its penetration 18 into the formation.
19 In still another embodiment of this invention, the steps in carrying out this invention may be repeated at least once. For example, 21 two or more cycles of the following steps may be carried out in the 22 practice of this invention (a) injecting into the formation an aqueous ;~
23 solution containing fluoride salts, (b) injecting into the formation a 24 hydrocarbon liquid, and (c) injecting into the formation an aqueous solution containing an acid.
26 Laboratory Tests 27 In order to demonstrate the effectiveness of this invention, 28 laboratory tests were run comparing various embodiments of this invention 29 with treatments typical of the prior state-of-the-art. The tests will be referred herein as Tests A, B, C, D, E, F, and G. Tests A and B
, ,,.~ , 1~18~i637 1 comprised alternately injecting solutions containing ammonium fluoride 2 and hydrochloric acid. Tests C, D, and E comprised embodiments of the 3 present invention. Test F comprised injecting common mud acid. Test G
4 comprised injecting a solution of ammonium fluoride and methyl formate.
All the tests used sand samples consisting of sand from the 6 bank of the Brazos River packed into rubber sleeves 48 inches long. In 7 tests A, B, C, F, and G the sleeve was 1 inch in diameter and in tests D
8 and E the sleeve was 1-1/2 inch in diameter. The rubber sleeves were 9 then encased in a steel cylinder and compressed with hydraulic fluid to maintain a dense pack during the test. The tests were conducted at a 11 temperature of 150F. After treatment, the sand packs were removed from 12 the steel cylinders and the rubber sleeves were opened. The clay 13 content was determined on the sand samples collected along the length of 14 the sand pack. Clay content was determined by its cation exchange capacity from a methylene blue titration according to the method described 16 in Bulletin API RP 13B entitled, "Standard Procedure for Testing Drilling 17 Fluids", published in February, 1974 by the American Petroleum Institute.
18 The following describes the treatment steps on the sand samples 19 for Tests A, B, C, D, E, F, and G. The hydrochloric acid solutions used in these tests typically contained a commercial corrosion inhibitor, 21 Corexit 8503, sold by Exxon Chemical Company.
22 Test A
23 The sand pack used for this test was l-inch in diameter and 48-24 inches in length. The pore volume (PV) was 205 cubic centimeters (cc).
During the acidizing test sequence, all fluids were pumped at a flow 26 rate of 7cc per minute.
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1 1. To prepare the sand sample for the test, calcium carbonate was 2 removed from the sand by pumping:
3 (a) 1.0 PV 8 wt% NaCl brine 4 (b) 7.3 PV 3 wt% HC1 2. The acidizing test was conducted by pumping 6 cyles of treating 6 chemicals. Each cycle consisted of:
7 (a) 0.13 PV 5 wt% HCl with 0.1 volume percent Corexit 8503 8 (b) 0.13 PV 0.8 molar NH4F in water (pH 8.5) 9 3. To prepare the sand for clay analysis, it was necessary to remove all resident fluid from the sand pack. This was 11 accomplished by pumping:
12 (a) 1.0 PV 5 wt% HCl with 0.1 vol% Corexit 8503 13 (b) 0.5 PV ethylene glycol isopropyl ether 14 (c) 1.20 PV pentane The sand pack was then blown dry with nitrogen 17 This test was conducted in essentially the same manner as described 18 for test A except that in step number two, 16 cycles of treating chemicals 19 were used.
TEST C
21 The sand pack used for this test was l-inch in diameter and 48-22 inches in length. The pore volume was l90cc. During the acidizing test 23 sequence, all fluids were pumped at a flow rate of 7cc per minute.
24 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl 26 (c) 0.25 PV 15 wt% HCl with 0.4 vol% Corexit 8503 27 (d) 0.50 PV 4 wt% NH4Cl brine .. . . . .
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108663~
1 2. The acidizing test was conducted by pumping:
2 ; (a) 0.25 PV 6 molar NH4F in water (pH 8.5) 3 (b) 0.25 PV diesel oil 4 (c) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503 3. To prepare the sand for clay analysis, it was necessary to 6 remove all resident fluid from the sand pack. This was 7 accomplished by pumping:
8 (a) l.0 PV l wt% HCl 9 (b) O.S PV ethylene glycol mono isopropyl ether (c) 1.2 PV pentane 11 The sand pack was then blown dry with nitrogen gas.
12 Test D
13 The sand pack used for this test was 1-1/2 inches in diameter 14 and 48 inches in length. The pore volume was 435cc. During the acidizing test sequence, all fluids were pumped at a flow rate of 15cc 16 per minute.
17 1. To prepare the sand for the test, calcium carbonate 18 was removed from the sand by pumping:
l9 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl plus 4 wt% N~4Cl 21 (c) 0.25 PV 15 wt% HCl with 0.5 vol % Corexit 8503 22 (d) 1.5 PV 4 wt% NH4Cl brine 23 2. The acidizing test was conducted by pumping:
24 (a) 0.25 PV 10 molar NH4F in water (pH 8.5) (b) O.S0 PV diesel oil 26 (c) 0.50 PV diesel oil containing 15 vol % ethylene glycol 27 monobutyl ether (a surface-active compound) 28 (d) 1.25 PV diesel oil 29 (e) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503 ~86637 3. To prepare the sand for clay analysis, it was necessary to 2 remove all of the resident fluid from the sand pack. This 3 was accomplished by pumping:
4 (a) l.0 PV l wt% HCl (b) 0.50 PV isopropyl alcohol 6 (c) 1.5 PV pentane 7 The sand pack was then blown dry with nitrogen gas.
9 The sand pack used for this test was l-l/2 inches in diameter and 48 inches in length. The pore volume was 455cc. During the acidizing 11 test sequence, all fluids were pumped at a flow rate of 15cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was 13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl plus 4 wt% NH4Cl 16 (c) 0.25 PV 15 wt% HCl with 0.5 vol% Corexit 8503 17 (d) 1.5 PV 4 wt% NH4Cl brine 18 2. The acidizing test was conducted by pumping:
19 (a) 0.35 PV 10.3 molar NH4F in water (pH 8.5) containing 0.3 wt% poly 2-acrylamido-2-methyl 21 propyl sulfonate (a viscosifier) 22 (b) 0.50 PV diesel oil 23 (c) 0.50 PV diesel oil containing 10 vol% ethylene glycol 24 monobutyl ether (a surface-active compound) and containing 0.2 vol% sorbitan monooleate (a 26 surface-active compound) 27 (d) 0.50 PV diesel oil 28 (e) l.0 PV 30 wt% HCl with 0.6 vol% Corexit 8503 :. . . ~;.
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1 3. To prepare the sand for clay analysis, it was necessary to 2 remove all of the resident fluid from the sand pack. This 3 was accomplished by pumping:
4 (a) l.0 PV 1 wt% HCl (b) 0.50 PV isopropyl alcohol 6 (c) 1.5 PV pentane 7 The sand pack was then blown dry with nitrogen gas.
9 The sand pack used for this test was l inch in diameter and 48 inches in length. The pore volume was 200cc. During the acidizing 11 test sequence, all fluids were pumped at a flow rate of 7cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was 13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine tb) 7.5 PV 3 wt% HCl 16 2. The acidizing test was conducted by pumping: -17 (a) 1.0 PV 3 wt% HF plus 12 wt% HCl containing 0.5 vol%
18 Corexit 8503 19 3. To prepare the sand for clay analysis it was necessary to remove all the resident fluid from the sand pack. This was 21 accomplished by pumping:
22 (a) 0.50 PV ethylene glycol mono isopropy]. ether 23 (b) 1.20 PV pentane 24 The sand pack was then blown dry with nitrogen gas.
TEST G
26 The sand pack used for this test was 1 inch in diameter and 27 48 inches in length. The pore volume was 170cc. During the acidizing 28 test sequence, all fluids were pumped a~ a flow rate of 7cc per minute.
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10866~37 1 1. To prepare the sand for the test, calcium carbonate 2 was removed from the sand by pumping: -3 (a) 1.0 PV 8 wt% NaCl brine 4 (b) 7.5 PV 3 wt% HCl plus 6 wt% NaCl (c) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03 6 (d) 1.3 PV 4 wt% NH4Cl brine 7- 2. The acidizing test was conducted by pumping:
8 1.1 PV 1 molar NH4F plus 2 molar methyl 9 formate in water 3. To prepare the sand for clay analysis, it was necessary to 11 remove all resident fluid from the sand pack. This was 12 accomplished by pumping:
13 (a) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03 14 (b) 0.5 PV ethylene glycol mono isopropyl ether (c) 1.20 PV pentane 16 The sand pack was then blown dry with nitrogen gas.
17 Results of tests A, B, C, D, E, F, and G are set forth in 18 FIGURE 2 which shows the relation between the clay content in percent of 19 the sand in the test samples and the distance in inches from the injection ends of the samples. The Brazos River sand used in these tests had an 21 initial clay content of 6.0 to 6.5 weight percent. This clay had an 22 ion exchange capacity of 0.58 milliequivalents per gram.
23 Curve F in FIGURE 2 is typical of the results obtained when 24 conventional mud acid (3 wt% HE, 12 wt% HCl) is used for clay removal.
Near the injection face, the remaining clay content is less than one-26 half of one percent. The clay content rises slowly to 1% at 24 inches 27 from the injection face, and then rises more rapidly approaching 6% clay 28 at 48 inches from the injection face. Examination of the sand after the 29 acid treatment revealed a large loss of silica within 2 to 3 inches of the injection face. It is this localized reaction zone that can break ;, .
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-- lOS6637 1 down the interface between the rock and the cement used to set the 2 wellbore casing thereby forming a path for undesirable water or gas to 3 reach the producing interval.
4 Curve G shows the results obtained with one prior art method for generating hydrofluoric acid in the formation pore spaces. A mixture 6 of ammonium fluoride and methyl formate was injected into the pore 7 space. The methyl formate hydrolyzed in the pore space to form formic 8 acid which in the presence of ammonium fluoride generated hydrofluoric 9 acid. As shown in FIGURE 2, the amount of clay dissolved by this tech-nique was small. Clay dissolution did occur fairly uniformly throughout 11 the entire sand volume with no obvious silica dissolution at the injection 12 face.
13 Curves A and B in FIGURE 2 represent another prior art process 14 to generate hydrofluoric acid in the pore space. In this method, alter-nate volumes of aqueous ammonium fluoride and hydrochloric acid are 16 pumped through the sand. There is no attempt to immobilize the liquids 17 containing fluoride or acid. The reported mechanism for hydrofluoric 18 acid generation is the attachment of fluorine ions to the anion exchange 19 sites of the clay minerals. Subsequent contact with hydrochloric acid generates hydrofluoric acid in the pore space. To achieve significant 21 clay removal, it is recommended to use multiple cycles of the NH4F-HCl 22 injection sequence. Curve A is the result from injecting 6 cyles of 23 treating fluids into a sand pack. About 50% of the clay in the sand 24 pack was removed by this treatment.
Increasing the number of NH4~-HCl cycles to 16 gives curve B
26 in FIGURE 2. Clay removal by this treatment was only slightly better 27 than the 6 cycle case, even though almost 3 times as much fluoride ion 28 was injected. Apparently, most of the fluoride ions are flowing through 29 the sand without encountering hydrochloric acid or generating hydro-fluoric acid.
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1 Curve C in FIGURE 2 is the result obtained by treating the 2 sand with one of the embodiments of the current invention. The injection 3 sequence consisted of an ammonium fluoride solution followed by diesel 4 oil and finally a strong hydrochloric acid solution. This test shows this treatment sequence is an improvement over the prior art techniques 6 discussed above. This improvement is attributed to the immobilization 7 of the ammonium fluoride solution by the diesel oil. The diesel oil 8 drives the fluoride solution to a saturation approaching residual water 9 saturation leaving the sand pack substantially free of mobile aqueous liquid.
ll At residual water saturation, the aqueous fluoride solution 12 primarily occupies the smaller pore spaces while diesel occupies the 13 larger pore spaces. When hydrochloric acid is injected, it can readily 14 displace diesel from the interior of the large pore spaces with only a small amount of fluoride displacement from the smaller pore spaces.
16 Owing to diffusion and mixing, the coexistence of fluoride ion and 17 hydrochloric acid in the pore space leads to the rapid generation of 18 hydrofluorice acid.
19 As shown by Curve C, the clay removal capability of this treatment is better than any of the prior art techniques for generating 21 hydrofluoric acid in the pore space. In addition, no apparent silica 22 dissolution occured near the injection face using the treatment designed 23 in accordance with this invention. This feature overcomes one of the 24 primary drawbacks to conventional mud acid treatments.
Another embodiment of the current invention is to employ a 26 surface active material in the diesel oil. The result of employing 27 ethylene glycol monobutyl ether (EGMBE) as a surface active material in 28 the diesel is shown as Curve D in FIGURE 2. The ammonium fluoride 29 solution was followed by diesel oil which drove the NH4F solution to a residual saturation of 37% by volume. Following this with diesel oil , .:, :, , containing 15 volume percent EGMBE lowered the fluoride solution satura-_ - 2 tion to 30%. Injection of untreated diesel oil completed the fluoride 3 immobilization sequence. With untreated diesel in the pore space, the 4 aqueous phase becomes mobile when the aqueous saturation Eeaches or e~ceeds 37%. Since the fluoride solution saturation had been reduced to 6 30% by the diesel-EGMBE mixture, the fluoride solution is not mobilized 7 by untreated diesel oil injected into the pore spaces.
8 Injecting hydrochloric acid into a sand prepared in the manner 9 described for Test D results in less displacement of the fluoride con-taining solution and consequently greater clay removal than Curve C.
11 Once again, silica dissolution at the injection face was avoided by the 12 use of this invention.
13 As previously described, another emboidment of this invention 14 is the use of an agent to increase the viscosity of the aqueous fluoride solution. The addition of 0.3 wt% of the potassium salt of poly-2-16 acrylamido-2-methyl propyl sulfonate (PAMPS) can increase the viscosity 17 of a 10-molar NH4F solution from 3 centipoises to 5 centipoises. Curve 18 E in FIGURE 2 was generated in a manner similar to curve D except that 19 0.3 wt~o PAMPS was included in the fluoride solution. The increased viscosity of the fluoride solution allowed it (l) to more efficiently 21 displace the resident aqueous fluid from the sand, and (2) to resist 22 being displaced itself by the aqueous hydrochloric acid solution.
23 Comparison of Curve E with the other clay removal data in 24 FIGURE 2 shows it to be clearly superior to other techniques for gener-ating hydrofluoric acid in the pore spaces. In fact, the clay removal 26 capability of this treatment approaches that for conventional mud acid 27 over the first 18 inches of the sand and is superior to mud acid in the 28 region beyond 18 inches. It is important to emphasize that unlike 29 conventional mud acid, silica dissolution was not observed at the injection face with the current invention.
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~LO~i637 1 Field Example 2 This example is provided to show how one embodiment of this 3 invention may be practiced in a field application. The sandstone 4 formation treated in this example is penetrated by a well. The forma- ;
tion has a porosity of 35 percent. The treatment ror this well is 6 designed to penetrate a 4-foot radius surrounding the well over any 7 desired formation interval. The formation has a pore volume of 130 8 gallons per foot of the formation interval. If the formation contains g carbonate minerals or it is desired to break down the perforations in the casing, a mixture containing 12 weight percent HCL and 3 weight 11 percent HF acids may be injected as a preflush liquid. All fluid injec-12 tion should be at a rate which maintains the injection pressure below 13 the formation fracture pressure. After the preflush, if carried out, 50 14 gallons per fcot of formation interval of an aqueous solution containing 4 weight percent NH4Cl is injected into the formation by means of the 16 well. This amount of ammonium chloride is injected into the formation 17 because generally about 1/3 pore volume is required to displace resident 18 aqueous fluids from the zone to be treated. About 40 gallons of an 19 aqueous solution containing 10.5 molar ammonium fluoride which contains 3000 parts per million potassium salt of poly 2-acrylamido-2-methyl 21 propyl sulfonate (PAMPS) is injected into the formation per foot of 22 formation interval. The amount of ammonium fluoride solution injected is 23 slightly more than the actual residual volume for the formation being 24 treated. The PAMPS is included in the ammonium fluoride solution to increase the solution viscosity to about 5 centipoises. After injection 26 of the ammonium fluoride solution, 50 gallons of diesel oil with 10% by 27 volume of ethylene glycol monobutyl ether (EGMBE) is injected into the 28 formation per foot of interval. Thereafter, 50 gallons per foot of 29 diesel oil without EGMBE is injected into the formation. After the 1~8~37 1 diesel oil is injected, 100 gallons per foot of an aqueous solution 2 containing 28 weight percent of HCl is injected into the formation. The 3 well is then returned to production.
4 It should be apparent that the foregoing method of the present invention offers significant advantages over sandstone acidizing methods 6 previously known in the art. It will be appreciated that while the 7 present invention has been primarily described with regard to the 8 foregoing embodiments, it should be understood that several variations 9 and modifications may be made in the embodiments described herein without departing from the broad inventive concept disclosed herein.
This is accomplished by immobilizing one of the aqueous solutions, in 31 the pore spaces of the formation by displacing solution with a liquid 1~86637 .
phase that is substantially immiscible with said aqueous phase, thereby driving said aqueous solution to a saturation at or below its residual saturation. The second aqueous solution is then injected into the formation.
More particularly, the present invention provides a method for acidizing a subterranean siliceous formation surrounding a wellbore wherein at least two aqueous solutions are injected into the formation, one of the aqueous solutions containing a fluoride salt and the other aqueous solution containing an acid, the improvement comprising the steps of ~ (a) injecting into the formation one of said aqueous solutions, (b) injecting into the formation a liquid that is substantially immiscible with said injected aqueous solution in an amount sufficient to substantially reduce the saturation of the injected aqueous solution in a substantial portion of the formation invaded by said aqueous solution in step (a); and - (c) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
In a preferred embodiment, water containing an ammonium salt of hydrofluoric acid is injected into the formation to be treated. The salt solution is then followed by a hydrocarbon liquid such as diesel oil to reduce the saturation of the salt solution to residual saturation. After the hydrocarbon liquid has been injected, hydrochloric acid solution is injected into the formation. The acid solution contacts the ammonium fluoride salts to form hydrofluoric acid which is capable of dissolving siliceous material in the formation.
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Other embodiments of this invention include adding various additives such as viscosifiers, surface active compounds and corrosion - inhibitors to the aqueous fluoride-containing solution and/or the injected hydrocarbon liquid and/or the aqueous acid-containing solution.
It is particularly preferred in the practice of this invention to inject into the formation an aqueous fluoride-containing solution which also contains a viscosifier such as a salt of poly 2-acrylamido-2-methyl propyl sulfonate and to inject into the formation a hydrocarbon which also contains one or more preferentially oil soluble surface-active compounds such as ethylene glycol monobutyl ether and/or sorbitan monooleate It is also particularly preferred in the practice of this invention to follow the aqueous fluoride containing solution with two sequential volumes of diesel oil; the first volume containing surface active compounds and the second volume being substantially free of surface-active compounds.
The practice of this invention provides an improved process for generating hydrofluoric acid in a formation. By this process, -6a-- : .. :- ,.
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1(~86637 1 hydrofluoric acid is continuously generated at and behind the advancing 2 hydrochloric acid front as it displaces the hydrocarbon liquid which 3 immobilized the fluoride salt solution from the pore spaces. In this 4 way hydrofluoric acid is generated at deeper radial depths into the formation than practicable prior to this invention. This invention sub-6 stantially alleviates the problems associated with rapid spending of 7 hydrofluoric acid within a short radial distance from the wellbore.
9 FIGURES 1 A-E are graphic illustrations of a formation showing the percentage saturations of fluids in the formation at various stages 11 in the processes of this invention.
12 FIGURE l-A shows the formation oil and water saturations prior 13 to the practice of this invention.
14 FIGURE l-B shows the formation fluids saturations as an aqueous fluid containing fluoride salts is injected into the formation.
16 FIGURE l-C shows the formation fluid saturations as a hydro-17 carbon fluid such as diesel oil is injected into the formation.
18 FIGURE l-D shows the formation fluid saturations wherein the 19 oil has reduced the saturation of the fluoride-containing fluid tG
residual saturation.
21 FIGURE l-E shows the formation fluid saturations as an aqueous 22 solution containing an acid is injected into the formation.
23 FIGURE 2 is a graph of laboratory tests on several sand samples 24 showing the relation between clay content in percent and distance in inches from the ends of the samples into which fluids were injected.
26 The results illustrated in this FIGURE show the improvement of the 27 present invention over several prior ar-t processes.
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1~86637 1 DESCRIPTION OF THE PREFERRED EMBODI~IENTS
2 The present invention is particularly useful for treating a 3 subterranean sandstone formation to improve effective permeability by 4 dissolving siliceous materials. These materials may comprise fine particles of sand, clay, silica or other silicate minerals, as well as 6 intergranular cementing material in the pores of a subterranean formation, 7 or a sand or gravel pack in the borehole of the well.
8 The present invention is an improved technique for generating - 9 hydrogen fluoride in a subterranean sandstone formation. In a preferred embodiment of this invention fluoride ion-containing salt solution is 11 injected into the formation and then immobilized in the pore spaces of 12 the formation by injection of a hydrocarbon liquid. An aqueous solution 13 containing an acid is then injected into this formation to generate 14 hydrofluoric acid. The method effectively produces hydrofluoric acid uniformly over the entire region containing immobile fluoride compounds.
16 Substantial penetration of the formation can therefore be achieved with 17 the active acid solution of hydrochloric and hydrofluoric acids.
18 The practice of a preferred embodiment of this invention may 19 be explained more clearly by referring to FIGS. lA, B, C, D, and E.
FIGURE l-A illustrates the oil and brine saturation in the subterranean 21 formation prior to the practice of this invention. In this portion of 22 the formation, the oil saturation is considered to be at residual oil 23 saturation. This condition which will exist after brine is injected 24 into an oil-bearing reservoir. FIGS. l B-E show the formation fluid saturations as the formation is being flooded with fluids in accordance 26 with this invention. Advancing fluid fronts are shown by vertical 27 lines, but it is understood that such interfaces are usually irregular 28 and are not well defined.
1 The first step in this embodiment is to inject into the forma-2 tion by means of a well an aqueous solution containing a fluoride salt.
3 As shown in FIGURE l-B, the fluoride-containing solution drives the 4 brine away from the wellbore and bypasses the residual oil in the forma-tion pore spaces. After a suitable amount of the aqueous liquid has 6 been injected, a hydrocarbon solution such as diesel oil is injected 7 into the formation. As shown in FIGURE l-C, the injected oil drives the 8 mobile aqueous fluoride-containing solution away from the wellbore 9 leaving an immobile residual saturation of the fluoride-containing solution. If a sufficient amount of oil is injected into the formation, 11 the oil will reduce essentially all the fluoride-containing solution to 12 its residual saturation (as depicted in FIG. l-D). By definition when 13 the fluoride-containing solution is at or below its residual saturation, 14 it cannot flow (it is immobiliæed) as oil phase flows through the pore space around it. After a suitable amount of hydrocarbon has been injected, 16 an aqueous solution containing an acid is injected in the formation.
17 The acid solution drives the mobile hydrocarbon away from the wellbore, 18 replaces the displaced oil with aqueous acid and reduces the oil satura-19 tion in the formation to its residual saturation. The aqueous fluoride-containing solution is not displaced ahead of the acid solution. Rather, 21 the acid solution mixes with the previously residual fluoride ion-22 containing solution as it is encountered to continuously form hydrogen 23 fluoride at the advancing acid front. The generation of hydrogen fluoride24 continues for some distance behind the acid front as fluoride ions diffuse out of the smaller pore spaces and acid diffuses into them. The 26 hydrogen fluoride thus generated can dissolve siliceous materials in the 27 formation. Since the clay minerals react with hydrogen fluoride several 28 orders of magnitude faster than other siliceous materials, clay is 29 preferentially removed.
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~0~36637 1 The aqueous fluid containing fluoride salt is preferably 2 formed from water which is substantially free of metal ions because many 3 metal ions complex or precipitate fluoride ions or reaction products 4 thereof.
The amount of fluoride-containing fluid injected will vary 6 depending on the extent of formation damage, the formation porosity, and 7 the permeability of the formation to flow of aqueous fluoride-containing 8 solution. Generally about l barrel to about 20 barrels of liquid are 9 injected per foot of formation interval to be treated.
The water-soluble fluoride salts used in the present invention 11 can comprise one or more of substantially any fluoride salt that is 12 water soluble. Ammonium salts of hydrofluoric acid, i.e. ammonium 13 fluoride or ammonium bifluoride, are preferred fluoride salts for use in 14 the present process. In using ammonium bifluoride (NH4HF2) it may be desirable to add enough ammonia or ammonium hydroxide to provide sub-16 stantially equimolar amounts of ammonium and fluoride ions.
17 The concentration of fluoride salt in the aqueous solution can 18 vary widely depending on the degree of damage to be removed and porosity 19 of the formation. As is well known, the amount of siliceous material that will be dissolved can be increased by increasing the concentration 21 of the hydrofluoric acid. Therefore, it is generally preferred to 22 contact the siliceous material with a strong solution. In many prior 23 art processes, strong HF solutions cause permeability damage due to 24 reaction generated pricipitates and fines. For example, permeability damage frequently occurs when a high HF concentration is injected at the 26 formation face because a majority of the reaction with the formation 27 matrix occurs in the small formation volume near the face. In the 28 present invention permeability damage is alleviated because hydrogen 29 fluoride is generated over the entire region containing fluoride salts so that the concentration of reaction generated precipitates and fines 31 remains low and uniformly distributed.
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108~637 1 The liquid injected into the formation after injection of the 2 aqueous liquid-containing fluoride salts may be any liquid which is 3 substantially immiscible with the aqueous fluoride-containing solution 4 and will immiscibly displace aqueous liquids in a porous medium. Examples of suitable liquids include perflurohexane, perflurooctane, cyclohexanone, 6 dioctyl ether, decanol, and hydrocarbons including kerosene, light 7 crude oil, diesel oil, and xylene. For economic reasons, the aqueous 8 immiscible liquid will most frequently be a hydrocarbon. The use of 9 diesel fuel or similar low viscosity petroleum fraction is generally preferred.
11 The amount of hydrocarbon or other liquid immiscible with the 12 aqueous solution injected into the formation will vary depending on the 13 amount of fluoride-containing solution injected into the formation.
14 Preferably, a sufficient volume of liquid is injected to reduce sub~
stantially all of the fluoride-containing solution to residual fluid 16 saturation. Generally the volume of injected hydrocarbon will be about 17 the same as the volume of the injected aqueous solution containing 18 fluoride salts.
19 In the most preferred embodiment, two hydrocarbon-volumes will be injected sequentially. In this embodiment, the first volume will 21 contain a low molecular weight preferentially oil soluble surface-active 22 agent such as ethylene glycol monobutyl ether and/or a higher molecular 23 weight preferentially oil soluble surface-active agent such as sorbitan 24 monooleate. The second volume will contain no surface active agent.
The object of this two-volume sequence is to reduce the fluoride salt 26 containing solution to a saturation substantially below the residual 27 satuation obtainable with the untreated hydrocarbon fluid. This lower 28 saturation will further assure immobilization of the fluoride solution 29 after injection of the untreated hydrocarbon fluid and will minimize the volume of any subsequent mixing zone between fluoride solution and , . . ;. - : .
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. .: .: : ., : :. ~ i ~086637 1 pursuing acid solution. Each hydrocarbon volume may be about the same 2 as the volume of injected aqueous fluoride solution.
3 Any water soluble acid generally employed in acidizing treat-4 ments may be utilized in the practice of this invention. Suitable acids include, for example, halogen acids such as HCl, HI, and HBr; mineral 6 acids such as sulfuric, nitric, and phosphoric; organic acids such as 7 acetic, proponic acid, and formic acid; modified organic acids such as 8 mono-, di-, and trichloroacetic acids; and, various mixtures thereof.
9 Hydrochloric acid (HCl) is generally preferred. The acid solution can contain up to about 38% by weight of these acids.
11 Viscosity increasing agents may be added to any of the injected 12 fluids in the practice of this invention. Preferably the aqueous fluoride-13 containing solution has a higher viscosity than the injected hydrocarbon 14 fluid and this hydrocarbon fluid preferably has a higher viscosity than the aqueous solution containing acid. This viscosity relationship 16 allows the fluoride-containing solution to efficiently displace the 17 resident aqueous fluids from the pore space. It also reduces fluoride 18 displacement by the aqueous solution containing acid. A suitable visco-19 sifier for use in the aqueous fluoride-containing solution may include a salt of poly-2-acrylamido-2-methyl propyl sulfonate, or other polymeric 21 sulfonate salt.
22 A sufficient amount of acid is preferably injected into the 23 formation to react with all of the fluoride salts injected in the forma 24 tion. It is particularly preferred to inject acid in a significant stoichiometric excess relative to the amount of the fluoride salts in 26 the formation. High concentrations of acid are preferred so as to 27 maximize the concentration of hydrofluoric acid formed at the acid front 28 as it displaces the hydrocarbon bank and assure penetration into the 29 formation of hydrochloric acid to the same radial extent to which the fluoride salt solution has been immobilized. Acid concentrations in 31 excess of 2 molar are preferred.
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~L08~63~7 1 Various additives such as corrosion inhibitors, demulsifying 2 agents, surfactants, and viscosifiers, may be added to the aqueous fluid 3 containing fluoride salts, to the hydrocarbon fluid and/or the acid 4 solution. Suitable inhibltors include the inorganic arsenic compounds, acetylenic alcohols, thiophenols, quaternary ammonia compounds and 6 similar organic agents. Almost any of the surfactants capable of reducing 7 interfacial tension between oil and water may be used in this invention.
8 The surface-active agents selected, of course, should be compatible with 9 the injected hydrocarbon, the fluoride salts, and the acid solution. In the preferred case, they should be preferentially oil soluble and be 11 placed in the injected hydrocarbon. Specific surface active materials 12 which may be employed include, for example, ethylene glycol monobutyl 13 ether and sorbitan monooleate.
14 In performing the matrix acidizing treatment in accordance with this invention, it is desirable to inject all fluids without 16 fracturing the formation. The formation fracture pressure can be de-17 termined by conventional computation techniques employing known or 18 estimated properties of the formation. This pressure limitation de-19 termines the rate at which the acid solution can be injected. Normally from l to 20 barrels of fluoride salt solution per foot of formation, 21 internal to be treated is injected at a rate ranging between about 0.25 22 barrels to 5 barrels per minute.
23 Another embodiment of the present invention is to inject into 24 the formation by means of a well an aqueous solution containing an acid preferably hydrochloric acid. This acid solution is then immobilized by 26 injecting into the formation a liquid, preferably a hydrocarbon, which 27 is substantially immiscible with the acid solution. An aqueous solution 28 containing a fluoride salt, preferably an ammonium salt of hydrofluoric 29 acid, is then injected into the formation. The fluoride salt will contact the acid to form hydrofluoric acid.
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1~8663~
1 A further embodimen. of this invention is to inject a liquid 2 preflush into the formation prior to injection of the fluoride-3 containing solution. In this embodiment an acid solution is injected 4 into the formation. This acid may be intended to react with calcite and other carbonate materials in the formation and thus alleviate undesirable 6 dissipation of the hydrogen fluoride generated at a later stage of the 7 process. In this case the acid solution is preferably hydrochloric 8 acid. The acid so]ution may also be intended to break down the perfora-9 tions in the casing and thereby establish good communication between the well bore and the siliceous formation. In this case the acid solution 11 is preferably a mixture of hydrochloric and hydrGfluoric acids known as 12 mud acid. This acid solution should then be followed with an aqueous 13 solution, preferably an ammonium chloride solution, neutralized with 14 ammonium hydroxide, or ammonium carbonate or ammonium bicarbonate. This aqueous solution serves to displace acid from the formation pore space 16 to be treated so as to prevent premature activation of the fluoride ion 17 containing solution of this invention which may limit its penetration 18 into the formation.
19 In still another embodiment of this invention, the steps in carrying out this invention may be repeated at least once. For example, 21 two or more cycles of the following steps may be carried out in the 22 practice of this invention (a) injecting into the formation an aqueous ;~
23 solution containing fluoride salts, (b) injecting into the formation a 24 hydrocarbon liquid, and (c) injecting into the formation an aqueous solution containing an acid.
26 Laboratory Tests 27 In order to demonstrate the effectiveness of this invention, 28 laboratory tests were run comparing various embodiments of this invention 29 with treatments typical of the prior state-of-the-art. The tests will be referred herein as Tests A, B, C, D, E, F, and G. Tests A and B
, ,,.~ , 1~18~i637 1 comprised alternately injecting solutions containing ammonium fluoride 2 and hydrochloric acid. Tests C, D, and E comprised embodiments of the 3 present invention. Test F comprised injecting common mud acid. Test G
4 comprised injecting a solution of ammonium fluoride and methyl formate.
All the tests used sand samples consisting of sand from the 6 bank of the Brazos River packed into rubber sleeves 48 inches long. In 7 tests A, B, C, F, and G the sleeve was 1 inch in diameter and in tests D
8 and E the sleeve was 1-1/2 inch in diameter. The rubber sleeves were 9 then encased in a steel cylinder and compressed with hydraulic fluid to maintain a dense pack during the test. The tests were conducted at a 11 temperature of 150F. After treatment, the sand packs were removed from 12 the steel cylinders and the rubber sleeves were opened. The clay 13 content was determined on the sand samples collected along the length of 14 the sand pack. Clay content was determined by its cation exchange capacity from a methylene blue titration according to the method described 16 in Bulletin API RP 13B entitled, "Standard Procedure for Testing Drilling 17 Fluids", published in February, 1974 by the American Petroleum Institute.
18 The following describes the treatment steps on the sand samples 19 for Tests A, B, C, D, E, F, and G. The hydrochloric acid solutions used in these tests typically contained a commercial corrosion inhibitor, 21 Corexit 8503, sold by Exxon Chemical Company.
22 Test A
23 The sand pack used for this test was l-inch in diameter and 48-24 inches in length. The pore volume (PV) was 205 cubic centimeters (cc).
During the acidizing test sequence, all fluids were pumped at a flow 26 rate of 7cc per minute.
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1 1. To prepare the sand sample for the test, calcium carbonate was 2 removed from the sand by pumping:
3 (a) 1.0 PV 8 wt% NaCl brine 4 (b) 7.3 PV 3 wt% HC1 2. The acidizing test was conducted by pumping 6 cyles of treating 6 chemicals. Each cycle consisted of:
7 (a) 0.13 PV 5 wt% HCl with 0.1 volume percent Corexit 8503 8 (b) 0.13 PV 0.8 molar NH4F in water (pH 8.5) 9 3. To prepare the sand for clay analysis, it was necessary to remove all resident fluid from the sand pack. This was 11 accomplished by pumping:
12 (a) 1.0 PV 5 wt% HCl with 0.1 vol% Corexit 8503 13 (b) 0.5 PV ethylene glycol isopropyl ether 14 (c) 1.20 PV pentane The sand pack was then blown dry with nitrogen 17 This test was conducted in essentially the same manner as described 18 for test A except that in step number two, 16 cycles of treating chemicals 19 were used.
TEST C
21 The sand pack used for this test was l-inch in diameter and 48-22 inches in length. The pore volume was l90cc. During the acidizing test 23 sequence, all fluids were pumped at a flow rate of 7cc per minute.
24 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl 26 (c) 0.25 PV 15 wt% HCl with 0.4 vol% Corexit 8503 27 (d) 0.50 PV 4 wt% NH4Cl brine .. . . . .
.: , .
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108663~
1 2. The acidizing test was conducted by pumping:
2 ; (a) 0.25 PV 6 molar NH4F in water (pH 8.5) 3 (b) 0.25 PV diesel oil 4 (c) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503 3. To prepare the sand for clay analysis, it was necessary to 6 remove all resident fluid from the sand pack. This was 7 accomplished by pumping:
8 (a) l.0 PV l wt% HCl 9 (b) O.S PV ethylene glycol mono isopropyl ether (c) 1.2 PV pentane 11 The sand pack was then blown dry with nitrogen gas.
12 Test D
13 The sand pack used for this test was 1-1/2 inches in diameter 14 and 48 inches in length. The pore volume was 435cc. During the acidizing test sequence, all fluids were pumped at a flow rate of 15cc 16 per minute.
17 1. To prepare the sand for the test, calcium carbonate 18 was removed from the sand by pumping:
l9 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl plus 4 wt% N~4Cl 21 (c) 0.25 PV 15 wt% HCl with 0.5 vol % Corexit 8503 22 (d) 1.5 PV 4 wt% NH4Cl brine 23 2. The acidizing test was conducted by pumping:
24 (a) 0.25 PV 10 molar NH4F in water (pH 8.5) (b) O.S0 PV diesel oil 26 (c) 0.50 PV diesel oil containing 15 vol % ethylene glycol 27 monobutyl ether (a surface-active compound) 28 (d) 1.25 PV diesel oil 29 (e) 0.50 PV 30 wt% HCl with 0.6 vol% Corexit 8503 ~86637 3. To prepare the sand for clay analysis, it was necessary to 2 remove all of the resident fluid from the sand pack. This 3 was accomplished by pumping:
4 (a) l.0 PV l wt% HCl (b) 0.50 PV isopropyl alcohol 6 (c) 1.5 PV pentane 7 The sand pack was then blown dry with nitrogen gas.
9 The sand pack used for this test was l-l/2 inches in diameter and 48 inches in length. The pore volume was 455cc. During the acidizing 11 test sequence, all fluids were pumped at a flow rate of 15cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was 13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine (b) 7.5 PV 3 wt% HCl plus 4 wt% NH4Cl 16 (c) 0.25 PV 15 wt% HCl with 0.5 vol% Corexit 8503 17 (d) 1.5 PV 4 wt% NH4Cl brine 18 2. The acidizing test was conducted by pumping:
19 (a) 0.35 PV 10.3 molar NH4F in water (pH 8.5) containing 0.3 wt% poly 2-acrylamido-2-methyl 21 propyl sulfonate (a viscosifier) 22 (b) 0.50 PV diesel oil 23 (c) 0.50 PV diesel oil containing 10 vol% ethylene glycol 24 monobutyl ether (a surface-active compound) and containing 0.2 vol% sorbitan monooleate (a 26 surface-active compound) 27 (d) 0.50 PV diesel oil 28 (e) l.0 PV 30 wt% HCl with 0.6 vol% Corexit 8503 :. . . ~;.
..
,~ - -. . : ~ ~ . .. .
1 3. To prepare the sand for clay analysis, it was necessary to 2 remove all of the resident fluid from the sand pack. This 3 was accomplished by pumping:
4 (a) l.0 PV 1 wt% HCl (b) 0.50 PV isopropyl alcohol 6 (c) 1.5 PV pentane 7 The sand pack was then blown dry with nitrogen gas.
9 The sand pack used for this test was l inch in diameter and 48 inches in length. The pore volume was 200cc. During the acidizing 11 test sequence, all fluids were pumped at a flow rate of 7cc per minute.
12 l. To prepare the sand for the test, calcium carbonate was 13 removed from the sand by pumping:
14 (a) 1.0 PV 8 wt% NaCl brine tb) 7.5 PV 3 wt% HCl 16 2. The acidizing test was conducted by pumping: -17 (a) 1.0 PV 3 wt% HF plus 12 wt% HCl containing 0.5 vol%
18 Corexit 8503 19 3. To prepare the sand for clay analysis it was necessary to remove all the resident fluid from the sand pack. This was 21 accomplished by pumping:
22 (a) 0.50 PV ethylene glycol mono isopropy]. ether 23 (b) 1.20 PV pentane 24 The sand pack was then blown dry with nitrogen gas.
TEST G
26 The sand pack used for this test was 1 inch in diameter and 27 48 inches in length. The pore volume was 170cc. During the acidizing 28 test sequence, all fluids were pumped a~ a flow rate of 7cc per minute.
,, , .: . .
. ~ - . :
10866~37 1 1. To prepare the sand for the test, calcium carbonate 2 was removed from the sand by pumping: -3 (a) 1.0 PV 8 wt% NaCl brine 4 (b) 7.5 PV 3 wt% HCl plus 6 wt% NaCl (c) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03 6 (d) 1.3 PV 4 wt% NH4Cl brine 7- 2. The acidizing test was conducted by pumping:
8 1.1 PV 1 molar NH4F plus 2 molar methyl 9 formate in water 3. To prepare the sand for clay analysis, it was necessary to 11 remove all resident fluid from the sand pack. This was 12 accomplished by pumping:
13 (a) 1.1 PV 4 wt% NH4Cl plus 2 wt% NH4HC03 14 (b) 0.5 PV ethylene glycol mono isopropyl ether (c) 1.20 PV pentane 16 The sand pack was then blown dry with nitrogen gas.
17 Results of tests A, B, C, D, E, F, and G are set forth in 18 FIGURE 2 which shows the relation between the clay content in percent of 19 the sand in the test samples and the distance in inches from the injection ends of the samples. The Brazos River sand used in these tests had an 21 initial clay content of 6.0 to 6.5 weight percent. This clay had an 22 ion exchange capacity of 0.58 milliequivalents per gram.
23 Curve F in FIGURE 2 is typical of the results obtained when 24 conventional mud acid (3 wt% HE, 12 wt% HCl) is used for clay removal.
Near the injection face, the remaining clay content is less than one-26 half of one percent. The clay content rises slowly to 1% at 24 inches 27 from the injection face, and then rises more rapidly approaching 6% clay 28 at 48 inches from the injection face. Examination of the sand after the 29 acid treatment revealed a large loss of silica within 2 to 3 inches of the injection face. It is this localized reaction zone that can break ;, .
.
, ~ . `~ ' - :
-- lOS6637 1 down the interface between the rock and the cement used to set the 2 wellbore casing thereby forming a path for undesirable water or gas to 3 reach the producing interval.
4 Curve G shows the results obtained with one prior art method for generating hydrofluoric acid in the formation pore spaces. A mixture 6 of ammonium fluoride and methyl formate was injected into the pore 7 space. The methyl formate hydrolyzed in the pore space to form formic 8 acid which in the presence of ammonium fluoride generated hydrofluoric 9 acid. As shown in FIGURE 2, the amount of clay dissolved by this tech-nique was small. Clay dissolution did occur fairly uniformly throughout 11 the entire sand volume with no obvious silica dissolution at the injection 12 face.
13 Curves A and B in FIGURE 2 represent another prior art process 14 to generate hydrofluoric acid in the pore space. In this method, alter-nate volumes of aqueous ammonium fluoride and hydrochloric acid are 16 pumped through the sand. There is no attempt to immobilize the liquids 17 containing fluoride or acid. The reported mechanism for hydrofluoric 18 acid generation is the attachment of fluorine ions to the anion exchange 19 sites of the clay minerals. Subsequent contact with hydrochloric acid generates hydrofluoric acid in the pore space. To achieve significant 21 clay removal, it is recommended to use multiple cycles of the NH4F-HCl 22 injection sequence. Curve A is the result from injecting 6 cyles of 23 treating fluids into a sand pack. About 50% of the clay in the sand 24 pack was removed by this treatment.
Increasing the number of NH4~-HCl cycles to 16 gives curve B
26 in FIGURE 2. Clay removal by this treatment was only slightly better 27 than the 6 cycle case, even though almost 3 times as much fluoride ion 28 was injected. Apparently, most of the fluoride ions are flowing through 29 the sand without encountering hydrochloric acid or generating hydro-fluoric acid.
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1 Curve C in FIGURE 2 is the result obtained by treating the 2 sand with one of the embodiments of the current invention. The injection 3 sequence consisted of an ammonium fluoride solution followed by diesel 4 oil and finally a strong hydrochloric acid solution. This test shows this treatment sequence is an improvement over the prior art techniques 6 discussed above. This improvement is attributed to the immobilization 7 of the ammonium fluoride solution by the diesel oil. The diesel oil 8 drives the fluoride solution to a saturation approaching residual water 9 saturation leaving the sand pack substantially free of mobile aqueous liquid.
ll At residual water saturation, the aqueous fluoride solution 12 primarily occupies the smaller pore spaces while diesel occupies the 13 larger pore spaces. When hydrochloric acid is injected, it can readily 14 displace diesel from the interior of the large pore spaces with only a small amount of fluoride displacement from the smaller pore spaces.
16 Owing to diffusion and mixing, the coexistence of fluoride ion and 17 hydrochloric acid in the pore space leads to the rapid generation of 18 hydrofluorice acid.
19 As shown by Curve C, the clay removal capability of this treatment is better than any of the prior art techniques for generating 21 hydrofluoric acid in the pore space. In addition, no apparent silica 22 dissolution occured near the injection face using the treatment designed 23 in accordance with this invention. This feature overcomes one of the 24 primary drawbacks to conventional mud acid treatments.
Another embodiment of the current invention is to employ a 26 surface active material in the diesel oil. The result of employing 27 ethylene glycol monobutyl ether (EGMBE) as a surface active material in 28 the diesel is shown as Curve D in FIGURE 2. The ammonium fluoride 29 solution was followed by diesel oil which drove the NH4F solution to a residual saturation of 37% by volume. Following this with diesel oil , .:, :, , containing 15 volume percent EGMBE lowered the fluoride solution satura-_ - 2 tion to 30%. Injection of untreated diesel oil completed the fluoride 3 immobilization sequence. With untreated diesel in the pore space, the 4 aqueous phase becomes mobile when the aqueous saturation Eeaches or e~ceeds 37%. Since the fluoride solution saturation had been reduced to 6 30% by the diesel-EGMBE mixture, the fluoride solution is not mobilized 7 by untreated diesel oil injected into the pore spaces.
8 Injecting hydrochloric acid into a sand prepared in the manner 9 described for Test D results in less displacement of the fluoride con-taining solution and consequently greater clay removal than Curve C.
11 Once again, silica dissolution at the injection face was avoided by the 12 use of this invention.
13 As previously described, another emboidment of this invention 14 is the use of an agent to increase the viscosity of the aqueous fluoride solution. The addition of 0.3 wt% of the potassium salt of poly-2-16 acrylamido-2-methyl propyl sulfonate (PAMPS) can increase the viscosity 17 of a 10-molar NH4F solution from 3 centipoises to 5 centipoises. Curve 18 E in FIGURE 2 was generated in a manner similar to curve D except that 19 0.3 wt~o PAMPS was included in the fluoride solution. The increased viscosity of the fluoride solution allowed it (l) to more efficiently 21 displace the resident aqueous fluid from the sand, and (2) to resist 22 being displaced itself by the aqueous hydrochloric acid solution.
23 Comparison of Curve E with the other clay removal data in 24 FIGURE 2 shows it to be clearly superior to other techniques for gener-ating hydrofluoric acid in the pore spaces. In fact, the clay removal 26 capability of this treatment approaches that for conventional mud acid 27 over the first 18 inches of the sand and is superior to mud acid in the 28 region beyond 18 inches. It is important to emphasize that unlike 29 conventional mud acid, silica dissolution was not observed at the injection face with the current invention.
~ . .
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~LO~i637 1 Field Example 2 This example is provided to show how one embodiment of this 3 invention may be practiced in a field application. The sandstone 4 formation treated in this example is penetrated by a well. The forma- ;
tion has a porosity of 35 percent. The treatment ror this well is 6 designed to penetrate a 4-foot radius surrounding the well over any 7 desired formation interval. The formation has a pore volume of 130 8 gallons per foot of the formation interval. If the formation contains g carbonate minerals or it is desired to break down the perforations in the casing, a mixture containing 12 weight percent HCL and 3 weight 11 percent HF acids may be injected as a preflush liquid. All fluid injec-12 tion should be at a rate which maintains the injection pressure below 13 the formation fracture pressure. After the preflush, if carried out, 50 14 gallons per fcot of formation interval of an aqueous solution containing 4 weight percent NH4Cl is injected into the formation by means of the 16 well. This amount of ammonium chloride is injected into the formation 17 because generally about 1/3 pore volume is required to displace resident 18 aqueous fluids from the zone to be treated. About 40 gallons of an 19 aqueous solution containing 10.5 molar ammonium fluoride which contains 3000 parts per million potassium salt of poly 2-acrylamido-2-methyl 21 propyl sulfonate (PAMPS) is injected into the formation per foot of 22 formation interval. The amount of ammonium fluoride solution injected is 23 slightly more than the actual residual volume for the formation being 24 treated. The PAMPS is included in the ammonium fluoride solution to increase the solution viscosity to about 5 centipoises. After injection 26 of the ammonium fluoride solution, 50 gallons of diesel oil with 10% by 27 volume of ethylene glycol monobutyl ether (EGMBE) is injected into the 28 formation per foot of interval. Thereafter, 50 gallons per foot of 29 diesel oil without EGMBE is injected into the formation. After the 1~8~37 1 diesel oil is injected, 100 gallons per foot of an aqueous solution 2 containing 28 weight percent of HCl is injected into the formation. The 3 well is then returned to production.
4 It should be apparent that the foregoing method of the present invention offers significant advantages over sandstone acidizing methods 6 previously known in the art. It will be appreciated that while the 7 present invention has been primarily described with regard to the 8 foregoing embodiments, it should be understood that several variations 9 and modifications may be made in the embodiments described herein without departing from the broad inventive concept disclosed herein.
Claims (37)
IS CLAIMED ARE DEFINED AS FOLLOWS:
1. In a method for acidizing a subterranean siliceous formation surrounding a wellbore wherein at least two aqueous solutions are injected into the formation, one of the aqueous solutions containing a fluoride salt and the other aqueous solution containing an acid, the improvement comprising the steps of (a) injecting into the formation one of said aqueous solutions, (b) injecting into the formation a liquid that is substantially immiscible with said injected aqueous solution in an amount sufficient to substantially reduce the saturation of the injected aqueous solution in a substantial portion of the formation invaded by said aqueous solution in step (a); and (c) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
2. The method as defined in claim 1 wherein the first injected solution contains fluoride salts and the second injected solution contains acid.
3. The method as defined in claim 2 wherein the fluoride salt is an ammonium salt of hydrofluoric acid.
4. The method as defined in claim 2 wherein the acid is hydrochloric acid.
5. The method as defined in claim 1 wherein the first injected aqueous solution contains acid and the second injected aqueous solution contains fluoride salts.
6. The method as defined in claim 1 wherein the liquid sub-stantially immiscible with the first injected aqueous solution is a hydrocarbon.
7. The method as defined in claim 6 wherein the hydrocarbon is oil.
8. The method as defined in claim 1 wherein the first injected aqueous solution is more viscous than the second injected aqueous solution.
9. The method as defined in claim 1 wherein the liquid substantially immiscible with the first aqueous solution is less viscous than the first injected aqueous solution and is more viscous than the second injected aqueous solution.
10. The method as defined in claim 1 wherein the liquid substantially immiscible with the first injected aqueous solution contains at least one surface-active compound.
11. The method as defined in claim 10 wherein the surface active compound comprises ethylene glycol monobutyl ether.
12. The method as defined in claim 1 wherein the first injected aqueous solution contains at least one surface-active compound.
13. The method defined in claim 1 wherein the first injected aqueous solution contains a material to increase the solution viscosity.
14. The method as defined in claim 13 wherein the material to increase the solution viscosity comprises a polymeric sulfonate salt.
15. A method as in claim 14 wherein the material to increase the solution viscosity is a salt of poly-2-acrylamido-2-methyl propyl sulfonate.
16. The method as defined in claim 1 wherein the liquid substantially immiscible with the first injected aqueous solution com-prises at least 5 percent by volume of the total volume of the first injected aqueous solution.
17. The method as defined in claim 1 further comprising injecting an aqueous solution as a preflush into the formation prior to injecting the first aqueous solution.
18. The method as defined in claim 17 wherein the aqueous preflush solution is substantially free of metal ions.
19. The method as defined in claim 1 wherein an aqueous acid solution substantially free of hydrofluoric acid and adapted to dissolve multivalent metal carbonates is flowed into the formation ahead of said first injected aqueous solution.
20. The method as defined in claim 1 wherein the steps a, b, and c are repeated at least once.
21. The method as defined in claim 1 wherein the amount of said injected liquid that is substantially immiscible with said first injected aqueous solution is sufficient to reduce substantially all of said first injected solution to approximately residual fluid saturation.
22. The method as defined in claim 1 wherein the volume of said injected liquid that is substantially immiscible with said first injected aqueous solution is about the same as the volume of the first injected aqueous liquid.
23. The method as defined in claim 1 wherein the volume of said injected liquid that is substantially immiscible with said first injected aqueous solution is at least as large as the volume of the first injected aqueous liquid.
24. The method as defined in claim 1 wherein the volume of said injected liquid that is substantially immiscible with said first injected aqueous liquid ranges from about 1 barrel to about 20 barrels per foot of formation interval being treated.
25. In a method for acidizing a subterranean siliceous formation surrounding a wellbore wherein at least two aqueous solutions are injected into the formation, one of the aqueous solutions containing a fluoride salt and the other aqueous solution containing an acid, the improvement comprising the steps of (a) injecting into the formation one of said aqueous solutions;
(b) injecting into said formation a hydrocarbon liquid which contains at least one surface-active material;
(c) injecting into said formation a hydrocarbon liquid substantially free of surface-active material, the combined amounts of the hydrocarbon liquid containing surface-active material and the hydrocarbon liquid substantially free of surface-active material injected into said formation being sufficient to reduce the saturation of said injected aqueous solution in at least a portion of the formation invaded by said aqueous solution in step (a) to residual saturation; and (d) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
(b) injecting into said formation a hydrocarbon liquid which contains at least one surface-active material;
(c) injecting into said formation a hydrocarbon liquid substantially free of surface-active material, the combined amounts of the hydrocarbon liquid containing surface-active material and the hydrocarbon liquid substantially free of surface-active material injected into said formation being sufficient to reduce the saturation of said injected aqueous solution in at least a portion of the formation invaded by said aqueous solution in step (a) to residual saturation; and (d) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
26. A method for acidizing a subterranean siliceous formation surround-ing a wellbore which comprises the steps of (a) injecting into said formation an aqueous solution containing fluoride salts;
(b) injecting into the formation a hydrocarbon liquid which is substanti-ally immiscible with the aqueous solution containing fluoride salts in an amount sufficient to reduce the saturation of the inject-ed aqueous solution in a substantial portion of the formation invaded by said aqueous solution in step (a) to residual saturation;
and (c) injecting into the formation an aqueous solution containing an acid which on contact with the fluoride salts will form hydrogen fluoride and thereby dissolve siliceous material.
(b) injecting into the formation a hydrocarbon liquid which is substanti-ally immiscible with the aqueous solution containing fluoride salts in an amount sufficient to reduce the saturation of the inject-ed aqueous solution in a substantial portion of the formation invaded by said aqueous solution in step (a) to residual saturation;
and (c) injecting into the formation an aqueous solution containing an acid which on contact with the fluoride salts will form hydrogen fluoride and thereby dissolve siliceous material.
27. The method as defined in claim 26 wherein the fluoride salt is an ammonium salt of hydrofluoric acid.
28. The method as defined in claim 26 wherein the hydrocarbon comprises diesel oil.
29. The method as defined in claim 26 wherein the acid solution comprises a solution of hydrochloric acid.
30. A method for improving the permeability of siliceous formation surrounding a wellbore which comprises:
(a) injecting into the formation an aqueous liquid containing at least one water soluble fluoride salt;
(b) injecting into the formation a hydrocarbon liquid which is substantially immiscible with the auqeous liquid and will immiscibly displace the aqueous liquid in the formation, the amount of said hydrocarbon liquid injected into the formation being sufficient to reduce the saturation of the injected aqueous solution to residual saturation; and (e) injecting into the formation an aqueous solution which on contact with the fluoride salt forms hydrogen fluoride.
(a) injecting into the formation an aqueous liquid containing at least one water soluble fluoride salt;
(b) injecting into the formation a hydrocarbon liquid which is substantially immiscible with the auqeous liquid and will immiscibly displace the aqueous liquid in the formation, the amount of said hydrocarbon liquid injected into the formation being sufficient to reduce the saturation of the injected aqueous solution to residual saturation; and (e) injecting into the formation an aqueous solution which on contact with the fluoride salt forms hydrogen fluoride.
31. A method for acidizing a subterranean siliceous formation surrounding a wellbore which comprises:
(a) injecting into said formation an aqueous solution containing fluoride salts;
(b) injecting into said formation a hydrocarbon liquid which contains at least one surface-active material;
(e) injecting into said formation a hydrocarbon liquid substantially free of surface-active material, the combined amounts of the hydrocarbon liquid containing surface-active material and the hydrocarbon liquid substantially free of surface-active material being sufficient to reduce the saturation of the injected aqueous solution in at least a portion of the formation invaded by said aqueous solution to residual saturation; and (d) injecting into said formation an aqueous solution containing an acid which on contact with fluoride salts will form hydrogen fluoride and thereby dissolve siliceous material.
(a) injecting into said formation an aqueous solution containing fluoride salts;
(b) injecting into said formation a hydrocarbon liquid which contains at least one surface-active material;
(e) injecting into said formation a hydrocarbon liquid substantially free of surface-active material, the combined amounts of the hydrocarbon liquid containing surface-active material and the hydrocarbon liquid substantially free of surface-active material being sufficient to reduce the saturation of the injected aqueous solution in at least a portion of the formation invaded by said aqueous solution to residual saturation; and (d) injecting into said formation an aqueous solution containing an acid which on contact with fluoride salts will form hydrogen fluoride and thereby dissolve siliceous material.
32. The method as defined in claim 31 wherein the fluoride salt is an ammonium salt of hydrofluoric acid.
33. The method as defined in claim 31 wherein the surface-active material comprises ethylene glycol monobutyl ether.
34. The method as defined in claim 31 wherein the ammonium fluoride solution contains a viscosifier.
35. The method as defined in claim 31 wherein the acid in the aqueous solution is hydrochloric acid.
36. A method for acidizing a subterranean siliceous formation surrounding a wellbore which comprises:
(a) injecting into sand formation a solution of a fluoride salt;
(b) injecting a liquid hydrocarbon into said formation to immiscibly displace said salt solution radially outwardly into the formation and to reduce the saturation of the salt solution in at least a portion of the invaded interval to residual saturation; and (c) injecting an acid solution into the formation, said acid solution combining with the fluoride salt solution to form hydrofluoric acid.
(a) injecting into sand formation a solution of a fluoride salt;
(b) injecting a liquid hydrocarbon into said formation to immiscibly displace said salt solution radially outwardly into the formation and to reduce the saturation of the salt solution in at least a portion of the invaded interval to residual saturation; and (c) injecting an acid solution into the formation, said acid solution combining with the fluoride salt solution to form hydrofluoric acid.
37. In a method for acidizing a subterranean siliceous formation surrounding a wellbore wherein at least two aqueous solutions are injected into the formation, one of the aqueous solutions containing a fluoride salt and the other aqueous solution containing an acid, the improvement comprising the steps of (a) injecting into the formation one of said aqueous solutions, (b) injecting into the formation a substantial volume of liquid that is substantially immiscible with said injected aqueous solution to reduce the saturation of the injected aqueous solution in a portion of the formation invaded by said aqueous solution in step (a) to approximately residual saturation;
(c) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
(c) injecting into the formation the other aqueous solution, said acid in one of said aqueous solutions combining with fluoride salts in the other aqueous solution to form hydrofluoric acid which is capable of dissolving siliceous material.
Priority Applications (1)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
CA314,190A CA1086637A (en) | 1978-10-25 | 1978-10-25 | Method for generating hydrofluoric acid in a subterranean formation |
Applications Claiming Priority (1)
Application Number | Priority Date | Filing Date | Title |
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CA314,190A CA1086637A (en) | 1978-10-25 | 1978-10-25 | Method for generating hydrofluoric acid in a subterranean formation |
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Publication Number | Publication Date |
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CA1086637A true CA1086637A (en) | 1980-09-30 |
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Application Number | Title | Priority Date | Filing Date |
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CA314,190A Expired CA1086637A (en) | 1978-10-25 | 1978-10-25 | Method for generating hydrofluoric acid in a subterranean formation |
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CA (1) | CA1086637A (en) |
-
1978
- 1978-10-25 CA CA314,190A patent/CA1086637A/en not_active Expired
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