Search Images Maps Play YouTube News Gmail Drive More »
Sign in
Screen reader users: click this link for accessible mode. Accessible mode has the same essential features but works better with your reader.

Patents

  1. Advanced Patent Search
Publication numberUS3868996 A
Publication typeGrant
Publication dateMar 4, 1975
Filing dateMay 15, 1974
Priority dateMay 15, 1974
Publication numberUS 3868996 A, US 3868996A, US-A-3868996, US3868996 A, US3868996A
InventorsKarnes George Thomas, Lybarger James H, Scheuerman Ronald F
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Buffer-regulated treating fluid positioning process
US 3868996 A
Abstract
The positioning of a treating fluid, such as an acidifying and/or particle-carrying fluid, in a subterranean location is improved by injecting a viscous, aqueous solution that contains a cellulose ether, a fluoride salt, a weak acid and a weak acid salt, and subsequently becomes a substantially non-viscous weakly acidic liquid that is capable of dissolving clay.
Images(3)
Previous page
Next page
Claims  available in
Description  (OCR text may contain errors)

United States Patent 1191 Lybarger et a1. 1 1 Mar. 4, 1975 [54] BUFFER-REGULATED TREATING FLUID 2,640,810 6/l953 Cardwell et a1 166/307 X 2,689,009 9/1954 Brainerd et a1. 166/307 POSITIONING PROCESS 3,417,820 12/1968 Epler et a1. 166/308 1 5] ntors: James H.Lybarger,Meta1r1e, 3,475,334 10/1969 Boudreaux 166/308 x Ronald F. Scheuerman, Bellaire; 3,483,121 12/1969 Jordan 166/308 X George Thomas Karnes, Houston, 3,543,856 12/1970 Knox et a1. 166/307 X both f T 3,727,688 4/1973 Clampitt 166/307 x 3,757,863 9/1973 Clampitt 166/307 1 1 Asslgneel Shell 01! p y, Houston, 3,765,488 10/1973 Pence, Jr. 166/308 [27] Filed y 15 1974 3,828,854 8/1974 Templeton et a1 166/307 9 9 [21] Appl. No.: 470,101 Primary E.\aminerStephen J. Novosad 521 US. Cl 166/250, 166/278, 166/307, 1571 ABSTRACT 166/308 The positioning of a treating fluid, such as an acidify- [51] Int. Cl... E21b 43/04, E2lb 43/26, E21b 43/27 ing and/or particle-carrying fluid, in a subterranean [58] Field of Search 166/250, 307, 308, 278, location is improved by injecting a viscous, aqueous 166/280, 281, 282, 271, 259, 300; 252/855 C solution that contains a cellulose ether, 21 fluoride salt, a weak acid and a weak acid salt, and subsequently [56] References Cited becomes a substantially non-viscous weakly acidic liq- UNITED STATES PATENTS uid that is capable of dissolving clay. 2,118,386 5/1938 Swinehart 166/307 UX 21 Claims, 4 Drawing Figures VISCOSITY PAIENIEW B 0 3,868,996 sumaij'a VISCOSITY PATENTEDHAR 41975 '''Ill llll sum-3 95 FIG. 4

BUFFER-REGULATED TREATING FLUID POSITIONING PROCESS RELATED PATENT APPLICATIONS The present invention is related to, but is distinct from, the buffer-regulated mud acid solutions of the type described in the E. A. Richardson patent application, Ser. No. 444,207 filed 2/21/74. The present invention utilizes reactants similar to those that form the buffer-regulated mud acid solutions in combination with a viscosifier with which they react to provide a selected strength and duration of the viscosity of the solution. The pertinent disclosures of the prior application are incorporated herein by cross-reference.

BACKGROUND OF THE INVENTION The present invention relates to a process, such as a well-treating process, in which a viscous fluid is pumped into a selected remote location, such as a subterranean location in or around the borehole of a well or a fracture. The invention is particularly useful for emplacing a slurry of particles that form a sand or gravel pack in or around a perforated casing in a well borehole, and/or within a fracture in a subterranean earth formation; for displacing a low-fluid-loss viscous, slow-reacting, acidic solution into and along the walls of a fracture; for temporarily diverting a relatively fast acting acid away from the more permeable zones that tend to act as thief-zones in an inhomogeneous permeable interval of earth formations in order to improve the permeability profile of the interval; and the like.

SUMMARY OF THE INVENTION The invention relates to a process for injecting fluid into a selected remote location such as a location in or around the borehole of a well. At least one each of a cellulose ether, a fluoride salt, a weak acid and a weak acid salt are dissolved in an aqueous liquid. The compositions and proportions of the dissolved materials are arranged to provide a weakly acidic solution that is capable of dissolving clay and has a selected relatively high viscosity that breaks in response to a time-andtemperature exposure of selected severity. The temporarily viscous solution, or a combination of it with relatively inert components that provide a treating fluid having substantially the same acidity and viscosity properties, is pumped into the selected subterranean location before its viscosity is significantly reduced.

DESCRIPTION OF THE DRAWING DESCRIPTION OF THE INVENTION In various situations, for example, where the treatment to be effected is primarily a delayed acidization,

' the injected fluid can comprise a temporarily viscous aqueous solution of the present type, with little or no additional material. Where relatively inert materials are combined with those solutions, the materials that are combined can comprise substantially any that can be dissolved in, emulsified with, or suspended in such a solution to form a fluid having at least one liquid phase that is a weakly acidic, aqueous solution that is capable of dissolving clay (and/or silica) and has a viscosity that is, temporarily, relatively high. Examples of inert materials suitable for use in the invention include solid particles such as sand, gravel, walnut shells, or the like for forming sand or gravel packs in well boreholes or masses of popping agents within fractures in subterranean earth formations, corrosion-inhibiting materials, wetting-agents, fluid loss preventative materials, chelating agents, etc., such as those used in conventional types of acidizing, fracturing, gravel packing, or the like, operations. Where the inert materials are soluble in a weakly acidic aqueous liquid, they can be combined with the temporarily viscous aqueous solution, or its components, during or after the compounding of the solution. Where the inert materials are to be emulsified with or suspended in such solutions, such materials are preferably combined with the solutions after all of the solutes have been dissolved.

The present invention is, at least in part, based on a discovery that, relative to uses in well-treating operations and the time-temperature exposures to which fluids are subjected during such operations: (a) a mixture of at least one each of a fluoride salt, a weak acid and a weak acid salt, is capable of breaking the viscosity of a cellulose ether-thickened aqueous solution, (b) a cellulose ether-thickened aqueous solution containing a mixture of at least one each of a fluoride salt, a weak acid and a weak acid salt, is capable of becoming (before or after the viscosity of the solution has been reduced) a solution that has a relatively high pH but is capable of dissolving siliceous material and/or weak acidsensitive material, and (c) the breaking time of the viscosity of a cellulose ether-thickened aqueous solution is sensitive to the pH of the solution (which is preferably within the range of from about 2 to 4) in a manner such that, at the temperatures usually encountered in well-treating operations, (within the range of from about to 250F), suitable viscosity-breaking times can be obtained by pHs of a mixture of at least one each of a fluoride salt, a weak acid, and a weak acid salt that provides a clay-dissolving weakly acidic solution.

Because of the above interrelation of properties, a slug of thepresent temporarily viscous, weakly acidic mud acid solution can be pumped into a depth interval containing permeable earth formations of different effective permeabilities, so that its viscosity tends to direct it into the most permeable portions, to there (a) dissolve fine particles of and thus to prevent permeability-impairment due to particle-movement, (b) divert portions of a more strongly acidic and faster-acting liquid to less permeable portions of the inverval, and (c) subsequently become a relatively non-viscous liquid that can readily be removed from the interval. Alternatively such a temporarily viscous solution can be used as the carrying liquid for a slurry of sand or gravel or fracture-propping materials that is pumped into a borehole or a fracture to provide a self-cleaning mass of the particles. In the latter procedure, substantially all of the particles and all portions of the mass of particles are immersed in a liquid that l) dissolves the clay or other acid-soluble fine particles (such as fines that were formed or entrained during the transporting of the slurry into the selected location), (2) maintains a pH that is relatively non-corrosive and (3) converts itself to a relatively non-viscous liquid that can readily be re moved from the so-cleaned mass of particles.

Aqueous liquids suitable for use in the present invention include pure water or substantially any relatively dilute aqueous liquid that is compatible with dissolved fluoride salts, weak acids, weak acid salts and the acidiflcation reaction products of hydrogen fluoride and clays or other siliceous materials. The aqueous liquid can advantageously contain additives such as corrosion inhibitors, wetting agent, detergents, oil solvents, oil and water mutual solvents, that are similarly compatible. Particularly suitable aqueous liquids include water or relatively dilute and soft saline solutions.

Fluoride salts suitable for use in the present invention include substantially any relatively water-soluble fluoride salt. The ammonium salts of hydrofluoric acid, such as ammonium fluoride and ammonium bifluoride, are particularly suitable. Where ammonium bifluoride is used, it is preferably mixed with enough ammonia or ammonia hydroxide to provide substantially equivalent proportions of ammonium and fluoride ions.

Weak acids that are suitable for use in the present invention include substantially any that dissolve in water to form an acidic solution adapted to convert fluoride ions to hydrogen fluoride. Examples of suitable weak acids include the water soluble fatty acids such as formic acid, acetic acid, and the like; substituted organic acids that are both relatively weak and water-soluble, such as chloroacetic acid, hydroxyacetic acid, and the like; various water-soluble polycarboxylic acids such as citric acid and the like. The weak acids can be used as individual acids or as mixtures of acids. Particularly suitable acids are formic, acetic and citric acids.

Weak acid salts suitable for use in the invention include substantially any water soluble salt of any weak acid of the type described above. Examples of suitable weak acid salts include the ammonium or alkali metal salts of the above acids, such as sodium or ammonium formate, sodium or ammonium acetate, sodium or ammonium citrate, or the like. The weak acid salts can be used as individual salts or as mixtures of salts. The salt of a given weak acid can be used with that acid or with one or more different weak acids. The latter arrangement can be utilized to provide a temporary adjustment in pH. For example, a relatively small proportion of a weak acid having a relatively high ionization constant (such as formic acid) can be mixed with a salt of a less ionized acid (such as ammonium acetate) to provide a solution having a pH that initially stays at a lower value than that exhibited after the depletion of the relatively highly ionized weak acid. Particularly suitable salts of weak acids include the ammonium salts of formic, acetic, and citric acids.

Where it is desirable to provide a temporarily viscous solution that is initially a relatively strongly acidic solution, a portion of a strong acid can be dissolved in the solution. While the strong acid is present, it over-rides the buffering action and depresses the pH of the solution. When the strong acid has been depleted, the pH rises to the value established by the buffering action corresponding to the relative proportions of weak acid and weak acid salt.

In the present temporarily-viscous solutions, the pH is strongly affected by the ionization constants and relative proportions of the weak acids and weak acid salts. In addition, where the fluoride salt concentrations are equivalent to less than about 5% by weight of aqueous hydrofluoric acid (about 2.5 moles per liter of the aqueous liquid), the hydrofluoric acid acts as a weak acid, and the fluoride salt acts as a weak acid salt. ln a solution containing a mixture of fluoride s'alt, weak acid, and weak acid salt, both the acidity of the solution and the rate of its dissolving of clay or weak acidsoluble material, decreases with increases in the pH of the solution. In addition, in a solution that contains a viscosifying amount of a cellulose ether, the rate at which the ether is hydrolyzed (which hydrolysis reduces the viscosity of the solution) is also decreased with increases in the pH of the solution.

In formulating the temporarily viscous solutions of the present invention, the composition and proportions of the cellulosic ether, fluoride salt, weak acid, and weak acid salt, are preferably correlated or arranged to provide both an adequateduration of the viscosity and an adequate capability of dissolving clay or acidsensitive material. The clay-dissolving capability is increaed by increasing the concentration of the fluoride salt (preferably to concentrations within a range equivalent to from about 0.1 to 3 moles per liter of hydrogen fluoride). The duration of the relatively high viscosity is increased (while decreasing the rate at which the solution dissolves clay or acid-sensitive material) by increasing the buffer-regulated pH of the solution (preferably to a pH within a range of from about 3 to 6). Where it is desirable to have a relatively high concentration of fluoride salt and still have a temporarily high viscosity of relatively short duration (along with a relatively rapid rate of acidification) the viscosity-breaking and initial acidification reaction rate can be increased by (a) adding a strong acid, such as hydrochloric acid, to the solution (preferably using less than an equal mo lecular proportion relative to the amount of weak acid) in order to temporarily override the buffer regulation of the pH, (b) using a weak acid having a relatively high ionization constant or (c), increasing the temperature of the subterranean location to be treated (as well as the conduit from that location to a surface location), for example, by inflowing a hot fluid.

Where the process of this invention is used for emplacing a self-cleaning mass or pack of particles in a selected location, the particles are preferably solid materials that are relatively slowly reactive with a mud acid (A HF-containing clay or silica-dissolving acid). Suitable particles include sand or gravel-sized, relatively spherical or well-rounded particles of silica sand grains, walnut shells, glass beads, mud-acid-resistant polymers, or the like. Where such particles are suspended in a temporarily viscous solution of this invention, the particles become emplaced in a mass in which all portions are permeated with a weakly acidic solution that is capable of dissolving clay or acid-sensitive fine particles. This tends to free the mass of any fine particles (such as fine sand, silt-sized, clay-sized, or smaller) of siliceous or acid-sensitive materials that are formed in or became mixed with, the pack particles. Such fine particles are commonly formed or entrained by the crushing and scraping action of the particles of a slurry that is flowed through pumps and/or conduits or along the face of earth formations, such as the walls of the borehole, or a fracture. The reactivities of the fine particles are many times greater than those of particles of from about It) to US mesh sieve sizes that are the preferred sizes for use in sand or gravel packing operations. When the packing particles and/or fracture-propping particles are suspended in the present temporarily viscous solutions and pumped into place,

the fines tend to be substantially completely dissolved with no significant loss of the packing particles, or other deleterious effect on the mass of packing particles.

Cellulose ether water thickeners that are suitable. for use in this invention, include substantially any acidsensitive cellulose ethers such as hydroxyalkyl, carboxyalkyl, or lower alkyl, cellulose ethers that are substantially completely water-soluble and are adapted to form water-soluble hydrolysis products when they are hydrolyzed in an acidic aqueous liquid. Examples of such cellulose ethers include hydroxyethylcellulose, carboxymethylcellulose, and the like. The hydroxyethylcelluloses available from Hercules Pattern Company, as Natrosol, those available .from Dowell as J-l64, or from Halliburton as WG-8, are particularly suitable.

The present invention provides an improved process for acidizing a fracture in a subterranean earth formation while the fracture is being formed, extended, and- /or packed with a propping agent. Fractures are formed by injecting fluid into a well at a pressure above the breakdown pressure of the surrounding earth formation. To keep the fracture open, a slurry of granular solids is injected to emplace a porous mass of particles between the walls of the fracture. While the fracture is being extended, the volume of the opening between its walls is determined by the injection rate and volume of the fracturing fluid, and the rate of fluid loss into the fracture walls. A relatively large volume of fluid free of fracture propping particles (although it may contain fine particles ofa fluid-loss material) is usually injected ahead of the slurry of propping particles. The temporarily high viscosity of the present well treatment fluids adapts them to be pumped through the fractures without rapidly leaking-off into the walls of the fractures. Their capability of reacting slowly, but relatively extensively, with clays or other silicious materials, adapts them to continue to dissolve such materials, and thus increasing the matrix permeability of the earth formations forming the walls of the fracture. In this connection, it is advantageous to use relatively high concentrations of fluoride salt to form relatively high pH temporarily viscous solutions that react slowly with respect to both the reduction of their viscosity, and the dissolving of clay, since such solutions can be allowed to remain in the fracture walls for relatively extensive times, such as one or more days.

As known to those skilled in the art, the severity of the time-temperature exposure of reactive materials, such as the present temporarily viscous aqueous solutions are increased by increases in either the degree of the temperature exposure for a given time, or the duration of the exposure at a given temperature. In a well treating operation, it is not usually feasible to make significant changes in the temperature of the subterranean location to be treated (or the conduit extending from it to a surface location) although some change can sometimes be made injecting a relatively hot or cold fluid. In addition, except in a fracturing operation, the rate at which fluid is pumped from a surface location to the subterranean location, is generally limited by the rate at which fluid can be flowed into the pores of the earth formation in response to a pressure less than the fracturing pressure. In formulating the present temporarily viscous solutions, the composition and proportions of the solution component are preferably arranged to provide a viscosity reduction in response to a time-temperature exposure that can feasibly be attained in pumping that solution into the particular subterranean location to be treated.

FIG. 1 illustrates a particularly suitable process for using the present invention in grave] packing a well. It shows a borehole 1 extended into a subterranean reservoir 2. The borehole contains a string of easing 3, surrounded by a sheath of cement 4 and penetrated by perforations 6, which provide openings into the reservoir. The invention also can be used in uncased boreholes or boreholes in which a casing is surrounded by a grouting material other than cement. A tubing string 7 which is connected to a screen or perforated liner 8 (along with appropriate packing, hanging, crossover devices, and the like, for a gravel-packing operation) has been inserted within the casing.

As indicated by the arrows, fluid is pumped through the tubing string and into the reservoir. The fluid preferably comprises a series of individual portions or slugs. The fluids shown in the Figure are preferably preceded by fresh water and/or an aqueous solution of an ammonium salt (such as ammonium chloride) and/or an acid adapted to dissolve carbonates or other reactive alkaline earth metal salts, where desirable to dissolve carbonate minerals and/or to displace reservoir water that contains a significant proportion of dissolved salts of alkali metals or alkaline earth metals. Slug 9 is a preformed mud acid. It can advantageously be a selfneutralizing solution of hydrochloric and hydrofluoric acids and a pH-increasing reactant of the type described in the co-pending patent application of E. A. Richardson and R. F. Scheuerman, Ser. No. 274,778, filed July 24, 1972 (the disclosures of which are incorporated herein by cross-reference). Slug 10 is a spacer slug, such as a relatively dilute aqueous solution (of not more than about 5% by weight) of ammonium chloride. Slug 11 is a buffer-regulated mud acid solution, comprising an aqueous solution of a fluoride salt, a weak acid and a weak acid salt in proportions that form a significant but low concentration of hydrogen fluoride, of the type described in the above-identified patent application Ser. No. 444,207. Slug 12 is a temporarily viscous solution of the present invention that contains a small proportion (such as about 3% by weight) of ammonium chloride, but is free of gravel-packing particles. Slug 12 functions as both a fines-removing mud acid and a viscous fluid that precedes the gravel pack particle-containing slurry for inhibiting the settling of pack particles while the pack particle-containing slurry and the fluid ahead of it are traveling through the conduits in the well.

Fluid 13a is a filtrate from slug l3. Slug 13 is a slurry of gravel-packing particles suspended in a temporarily viscous solution of the present invention. The filtrate 13a flows on into the reservoir as a temporarily viscous solution as the suspended packed grains are screened out against the face of the reservoir. Fluid 13b is a supernatent liquid comprising a temporarily viscous solution of the present invention, from which the gravelpacking grains have settled out (by gravity segregation) as portions of the slug l3 stands still or flows relatively slowly within the borehole.

Fluid 14 is an inert gravel packing slurry-displacing fluid, such as a relatively dilute aqueous solution of an ammonium halide. Fluid 14 can advantageously contain a pH-increasing reactant such as a readily hydrolyzable amide. The volume and extent of displacement of the slugs 13 and 14 are preferably controlled so that (a) slug 13 fills the annular space around the screen 8 and extends above the uppermost perforation 6 in the casing 3 and (b) slug l4 fills the portion of the casing above that space, up through the crossover assembly, and into the tubing string 7.

FIG. 2 shows the same portion of the same well at a later time, when fluid is being produced into the well from the reservoir 2. At this time the well contains a gravel pack 16, which hs been formed by the screening out and settling of the gravel pack particles that were transported by slurry l3.

As shown by the arrows, the produced fluid tends to flow directly from the perforations 6, through the gravel pack 16, and into the adjacent openings in the screen or liner 8. Thus, the produced fluid contacts only a small portion of the gravel pack and is confined within an inner conduit during most of its passage out of the well. Because of this, the production of fluid from the reservoir tends to leave a substantially undisturbed column of the fluids 1312 and/or 14 standing within and/or above the gravel pack 16. Since the fluid 14 is apt to be mixed with the substantially non-viscous but relatively weakly acidic liquid that is formed by the self-induced conversion of the supernatent temporarily viscous fluid 13b (shown in FIG. 1), the fluid 14 can advantageously contain a pH-increasing reactant for reducing the corrosiveness of an acidic liquid.

The flow patterns of fluids that are injected or produced through a well containing a gravel pack, are such that the self-cleaning aspect of the present process is particularly advantageous. In the present process the particle-suspending fluid (which is initially viscous and is distributed throughout the entirety of the gravel pack) comprises a weakly acidic and relatively slowlyreactive mud acid that tends to dissolve substantially all of any silt-sized or clay-sized fine particles of siliceous material or acid-soluble material that becomes entrained within the pack or along any of its peripheral areas. The perforations 6, or other open portions of borehole wall (e.g., the walls of an open hole or barefoot completion) through which fluids can flow between the interior of the well and the interior of the reservoir are, in effect, parallel flow paths. If one such path is plugged, most of all of the flow proceeds through another path. Because of this, it is seldom effective to inject a mud acid into a gravel pack (such as pack 16) after it has been emplaced. Such an injection usually fails to dissolve fines throughout any but small and preferentially permeable portions of the body of the pack or along the interfaces between the pack and- /or pack or perforations or perforation tunnels and the face of the reservoir.

In preparing a temporarily viscous solution of the present invention for use in a well, a volume of approximately 1,000 gallons is preferably mixed as follows; about 884 gallons of fresh water are mixed with about 80 pounds of a water-soluble hydroxyethylcellulose, 308 pounds of ammonium fluoride, and 250 pounds of ammonium chloride. Before pumping the solution into the well, about 85.6 gallons of aqueous 90% formic acid, and 29.75 gallons of aqueous 30% hydrochloric acid are added. This forms a temporarily viscous solution having a viscosity (in centipoises, about 350 at 80F and about 100 at 170F) that is significantly reduced by a time-temperature exposure equivalent to about 4 hours at I70F.

FIG. 3 shows the results of laboratory tests of the effect of pH on the viscosity-breaking times of aqueous solutions thickened with a hydroxyethylcellulose ether. Stock aqueous solutions were prepared by dissolving in potable water about pounds per 1,000 gallons of a commercially available hydroxyethylcellulose, 0.1 pound per barrel of water of sodium hydroxide, and 3% by weight (based on the water content) of ammonium chloride. The following reactants were then dissolved in the stock solution in proportions providing substantially the indicated pHs and number of moles per liter (based on the water content) of the following acidifying materials:

Solution A 2 moles formic acid, pH 1.5 Solution B 1 mole formic acid, pH 1.8 Solution C 1 mole acetic acid, pH 2.4 Solution D 0.75 mole formic acid, 0.25 mole sodium formate, pH 3.0

Solution E 1 mole formic acid, 1 mole sodium formate, pH 3.4

Solution F 0.5 mole formic acids, 0.5 mole sodium formate, pH 3.6

Solution G 1 mole acetic acid, 1 mole sodium acetate, pH 4.7

FIG. 3 shows the variations in the viscosities of the respective solutions (in terms of transit times in seconds through a No. 300 Ostwalt tube, in which a fulid having a viscosity of about 1 centipoise has a transit time of about 2.5 seconds) versus the time (in hours) at which the solutions were kept at a temperature of 180F. It is apparent that the extents of timetemperature exposure that causes a significant reduction in the viscosity of the tested solution (such as a reduction to about 10 centipoises, which corresponds to a transit time of about 25 seconds) increase with increases in the pH of the solutions. It is also apparent that a buffered system comprising a mixture of a weak acid and a weak acid salt can be used to adjust the pH of such a solution.

FIG. 4 shows the results of similar tests of similar solutions containing the same proportion of hydroxyethylcellulose. These solutions each contained about two moles per liter of formic acid and 1 mole per liter of ammonium fluoride and were maintained at F. The solutions differed from each other as follows:

Solution A contained 0.5 mole per liter hydrochloric acid, pH 3.0 Solution B contained 0.25 mole per liter hydrochloric acid, pH 3.3

Solution C contained no hydrochloric acid, pH 4.0

Test results, such as those shown in FIGS. 3 and 4, indicate the fluoride salt functions as a weak acid salt component of the buffer system that regulates the pH of the solution. For example, the 2m formic acid solution A of FIG. 3 has a pH of 1.5 while solution C of FIG. 4, which differs significantly only in an addition of 1 mole per liter of ammonium fluoride, has a pH of 4.0. Such tests also indicate that relatively small proportions ofa strong acid, such as hydrochloric acid, can be added to obtain a lower pH. The lower pH provides a quicker breaking of the viscosity, as well as a faster rate of dissolving a silicious material or a weak acid-soluble material. The more rapid acidizing effect of a relatively low pH is more completely described in the aboveidentified patent application Ser. No. 444,207.

What is claimed is:

l. A well treating process comprising dissolving in an aqeous liquid at least one each of a cellulose ether, a fluoride salt, a weak acid, and a weak acid salt;

arranging the composition and relative amounts of the solution components to provide a temporarily viscous solution that is weakly acidic but is capable of dissolving clay and has a selected relatively high viscosity that is significantly reduced in response to a time-temperature exposure of selected severity; and

flowing the temporarily viscous fluid into a subterranean location at a rate such that it at least substantially reaches the location to be treated before its viscosity has been significantly reduced.

2. The process of claim 1 in which at least a portion of the temporarily viscous solution is combined with relatively inert material, to form a treating solution having substantially the same acidity and viscosity properties, prior to flowing it into the subterranean location.

3. The process of claim 2 in which the relatively inert material includes solid particles adapted to form a sand or gravel pack or a fracture-propping mass of particles.

4. The process of claim 1 in which a relatively small proportion of strong acid is mixed with the temporarily viscous solution to increase its initial rate of reaction and reduce the duration of its relatively high viscosity.

5. The process of claim 1 in which the temporarily viscous solution is arranged to have a pH of from about 2 to 4.

6. The process of claim 1 in which the temporarily viscous solution is flowed into a fracture within a subterranean earth formation and, before flowing it into the fracture, the composition and proportions of its components are arranged to provide a relatively high pH.

7. The process of claim 6 in which slugs of the temporarily viscous solution are alternated with slugs of a relatively fast-acting acidic material.

8. A well treating process comprising dissolving in an aqueous liquid at least one each of a cellulose ether, a fluoride salt, aweak acid, and a weak acid salt;

arranging the compositions and proportions of said solutes to provide a temporarily viscous solution that is weakly acidic but is capable of dissolving clay and has a viscosity that is significantly reduced in response to a time-temperature exposure of selected severity;

combining the temporarily viscous solution with relatively inert material to the extent desired to provide an earth formating treating fluid having properties of acidity and viscosity substantially equaling those of the solution; and

flowing the earth formation treating fluid into a subterranean location to be treated before the solution viscosity is significantly reduced.

9. The process of claim 8 in which the earth formation treating fluid contains suspended solid particles adapted to form a permeable mass of particles in the subterranean location to be treated.

10. The process of claim 8 in which a relatively small proportion of a strong acid is mixed with the temporarily viscous solution to increase its initial rate of acidization reaction and reduce the duration of its relatively high viscosity.

11. The process of claim 8 in which the compositions and proportion of the components of the the temporarily viscous solution are arranged to provide a relatively high pH and the earth formation treating fluid containing that solution is flowed into a fracture within a subterranean earth formation.

12. In a well treating process in which a selfbreaking viscous fluid having a selected initial viscosity is injected into a selected subterranean location in response to a selected injection pressure, an improved process for ensuring that the viscosity-breaking occurs at a selected time after the solution has reached the selected location, which process comprises:

determining the magnitude of the time-temperature exposure of fluid that flows from a surface location to the selected subterranean location at the rate established by the selected injection pressure;

determining the pH at which an aqueous solution that contains enough cellulose ether to provide the selected viscosity mixed with an acid capable of inducing the breaking of the viscosity becomes a solution in which the viscosity-breaking occurs at the selected time after the solution has been subjected to a time-temperature exposure of the determined magnitude and is maintained at the temperature of the selected subterranean location; and

injecting as said self-breaking viscous fluid a cellulose ether-thickened aqueous solution having a pH substantially equaling the determined pH.

13. The process of claim 12 in which the pH of said injected fluid is established by a dissolved mixture of at least one weak acid and one weak acid salt in a ratio that buffers the pH at substantially the determined pH.

14. The process of claim 12 in which said injected fluid contains at least one dissolved salt of hydrofluoric acid.

15. The process of claim 14 in which said injected fluid has a pH of from about 2 to 4.

16. In a process in which the fluid is positioned in a selected remote location by forming a temporarily viscous fluid and flowing it into the selected location before the fluid viscosity is significantly reduced, the improvement which comprises:

dissolving in an aqueous liquid at least one each of a cellulose ether, a weak acid and a weak acid salt;

arranging the solution components to provide a weakly acidic solution having a viscosity that becomes significantly reduced in response to a timetemperature exposure of selected severity; and flowing the weakly acidic solution into the selected location at a rate causing it to arrive at least substantially as soon as it has received a time temperature exposure of the selected severity.

17. The process of claim 16 in which the selected location is a subterranean region in contact with earth formation in or around the borehole of a well.

18. The process of claim 16 in which the weak acid salt comprises a mixture of at least one salt of hydrofluoric acid and at least one salt of an organic acid.

19. The process of claim 18 in which the weakly acidic solution contains an amount of strong acid that is significant but less than equimolar relative to the amount of weak acid.

20. The process of claim 18 in which the strong acid is hydrochloric acid.

21. The process of claim 20 in which the pH of the buffer regulated solution is, initially, from about 2 to 4.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2118386 *Dec 27, 1933May 24, 1938Harshaw Chem CorpHydrofluoric acid composition
US2640810 *Sep 14, 1950Jun 2, 1953Dow Chemical CoTreatment of wells
US2689009 *Apr 14, 1951Sep 14, 1954Stanolind Oil & Gas CoAcidizing wells
US3417820 *Aug 27, 1965Dec 24, 1968Halliburton CoWell treating with aqueous gelled salt solutions
US3475334 *Apr 21, 1966Oct 28, 1969Dow Chemical CoHydraulic fracturing
US3483121 *Sep 6, 1966Dec 9, 1969Gen Mills IncFormation fracturing
US3543856 *Aug 19, 1969Dec 1, 1970Halliburton CoMethod of acidizing wells
US3727688 *Feb 9, 1972Apr 17, 1973Phillips Petroleum CoHydraulic fracturing method
US3757863 *Dec 27, 1971Sep 11, 1973Phillips Petroleum CoSecondary recovery methods
US3765488 *Apr 6, 1972Oct 16, 1973Dow Chemical CoWell treating method
US3828854 *Oct 30, 1973Aug 13, 1974Shell Oil CoDissolving siliceous materials with self-acidifying liquid
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4026361 *Jun 14, 1976May 31, 1977Shell Oil CompanyTreating wells with a temporarily thickening cellulose ether solution
US4504400 *Jan 9, 1984Mar 12, 1985The Dow Chemical CompanyFluid and method for placing gravel packs
US4518040 *Jun 29, 1983May 21, 1985Halliburton CompanyMethod of fracturing a subterranean formation
US5460225 *Jul 18, 1994Oct 24, 1995Shell Oil CompanyGravel packing process
US5529125 *Dec 30, 1994Jun 25, 1996B. J. Services CompanyAcid treatment method for siliceous formations
US7059414 *Jul 22, 2003Jun 13, 2006Bj Services CompanyAcidizing stimulation method using a pH buffered acid solution
US8590622Feb 10, 2006Nov 26, 2013Halliburton Energy Services, Inc.Organic acid compositions and methods of use in subterranean operations
US8622134 *Mar 5, 2009Jan 7, 2014Halliburton Energy Services, Inc.Organic acid compositions and methods of use in subterranean operations
US20050016731 *Jul 22, 2003Jan 27, 2005Rae Philip JamesAcidizing stimulation method using a pH buffered acid solution
Classifications
U.S. Classification166/250.1, 166/308.1, 166/307, 166/278
International ClassificationC09K8/60, E21B43/04, C09K8/72, E21B43/25, E21B43/02, E21B43/26
Cooperative ClassificationC09K8/72, E21B43/26, E21B43/045, E21B43/25
European ClassificationE21B43/25, C09K8/72, E21B43/04C, E21B43/26