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Publication numberUS3892275 A
Publication typeGrant
Publication dateJul 1, 1975
Filing dateJan 24, 1974
Priority dateJan 24, 1974
Publication numberUS 3892275 A, US 3892275A, US-A-3892275, US3892275 A, US3892275A
InventorsJames H Lybarger, Ronald F Scheuerman
Original AssigneeShell Oil Co
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Self-thinning and neutralizing thickened aqueous liquid
US 3892275 A
Abstract
A thickened aqueous liquid, suitable for suspending packing particles, comprises an aqueous solution containing an acid-reactive cellulosic water thickening material, an acidifying material that causes the solution viscosity to decrease after a selected time-temperature exposure, and a relatively slowly reactive material that causes the solution pH to increase to a selected value after a longer time.
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Description  (OCR text may contain errors)

7 l T5 XR 398925275 United States Patent 11 1 1111 3,892,275 Lybarger et al. July 1, 1975 [54] SELF-THIN NING AND NEUTliALIZING 3,415,318 l2/i958 Meijs 166/300 THICKENED LIQUID 3,826,312 7/l974 Richardson et al 166/307 [75] Inventors: James H. Lybarger, Metairie, La'.;

Ronald F. Scheuerman, Bellaire, Primary Examiner-Stephen J. Novosad Tex. Assistant Excimin'e'rGeorge Suckfield [73] Assignee: Shell Oil Company, Houston, Tex.

[221 Filed: Jan. 24, 1974 [57] RACT [21] Appl. No.: 436,290 1 1 A thickened aqueous liquid, suitable for suspending packing particles, comprises an aqueous solution con- [52] "166/250; 166/278; taining an acid feactive cellulosic water thickening Int C12 E218 43/04. E21B 43/27 material, an acidifying material that causes the solu- Fie'ld 166/250 294 307 tion viscosity to decrease after a selected time- 0 ar temperature exposure, and a relatively slowly reactive 166/270 305 R material that causes the solution pH to increase to a selected value after a longer time.

[56] 1 References Cited UNITED STATES PATENTS 5 Claims, 3 Drawing Figures 3,378,070 4/1968 Wessler et al. 166/294 a a, a SOLUTION -pH (NO. 300 TUBE) ova-1S I lcp FLUID TRANSr'T TIME I TRANSIT TIMES 17 SOLUTION pH 111' BASE HEC SOLUTION NO METHYL FORMATE 01 0.2 0.6 0.6 08 l 2 4 6 2L7 I 4L7 E O B U HYDROLYSIS TIME, HOURS PATENTEDJUL 1 SHEET FIG.

F/GZ

a. w A a BACKGROUND or THE INVENTION The present invention relates to a thickened aqueous liquid and its use in well treating processes, such as sand or gravel packing, fracturing, fluid-diverting, selective-plugging, fluid-displacing, or the like, processes. Prior well treating processes have used thickened aqueous liquids, and some of them have used cellulosic material water thickeners and acidic material viscosity breakers. Prior well treating processes are described in U.,S, patents such as: US. Pat. No. 3,778,472, describing cellulose ether-thickened reservoir acidizing solutions that are self-thinning; US. Pat. No. 3,024,195, describing fracturing fluids that are thickened with carboxymethylcellulose and thinned by a dissolved perborate;-U.S. Pat. No. 3,417,820, describing aqueous solutions of alkaline earth metal salts that are thickened with hydroxyethylcellulose and thinned with an oxidative or enzymatic breaker; US. Pat. No. 3,696,035, describing aqueous alcoholic solutions that are thickened with cellulose derivatives and thinned with a periodate or other oxidizing or reducing material, etc. The previously proposed acid-thinned aqueous solutions tend to become and/or remain relatively strongly acidic and thus corrosive. The thinning action of an oxidizying or reducing reactant in an aqueous solution containing a cellulosic thickening material tends to be unpredictably accelerated when the solution entrains in atmospheric oxygen in amounts that are apt to be unavoidable in the handling of fluids at a well site.

SUMMARY or THE INVENTION This invention provides a thickened aqueous liquid containing (a) enough dissolved acid-reactive cellulosic water thickener to provide a selected viscosity, b) an amount and composition of substantially homogeneously distributed acidifying material sufficient to cause a decrease in the viscosity of the solution after a selected time-temperature exposure, and I (c) an amount and composition of substantially homogeneously distributed relatively slowly-reactive pH- increasing material sufficient to raise thepH of the so- .lution to a selected substantially neutral value after an additional time.

The invention also provides a well treating process comprising:- determining the approximate time and temperature to which a fluid having a selected viscosity is subjected while being pumped, at a selected rate, into a zone to be treated within a well; compounding an aqueous liquid that contains (a) enough dissolved acidreactive cellulosic water thickener to provide the selected viscosity (b) an amount and composition of substantially homogeneously distributed acidifying material sufficient to cause a decrease in the solution viscosity within a selected time after the solution, when pumped atthe selected rate, has reached a selected depth within the well,and (c) an amount and composition of substantially homogeneously distributed relatively slowly reactive pH-increasing material sufficient to raise the pH of the solution to a selected substantially neutral value within a selected additionaltimep and, pumping the compounded aqueous liquid-into the well at substantially'the selected rate.

The present composition and process are useful in various operations, such as suspending and/or transporting substantially any dissolved or dispersed materials that are relatively inert with respect to the viscosityreducing and acid-neutralizing reactions.

DESCRIPTION OF THE DRAWING DESCRIPTION OF THE INVENTION The invention is, at least in part, premised on a discovery that: byusing an acid-sensitive cellulosic water thickener and-a slowly reactive pH-increasing material, the occurrenceof a self-thinning action within the thickened aqueous liquid can be relatively accurately timed with respect to rather widely varying timetemperature exposures, and the thinned solution can be caused to become a substantially neutral liquid that is non-corrosive to equipment such as that contained in a well.

Generally suitable acid-reactive cellulosic water thickeners include acid-sensitive cellulose, ethers such as the hydrdxyalkyl, carboxyalkyl, and lower alkyl, cellulose ethers, typified by hydroxyethylcellulose, carboxymethylcellulose, methylcellulose, or the like, which are substantially completely aqueous-liquidsoluble cellulose ethers that form substantially completely aqueous-'liquid-soluble hydrolysis products when hydrolyzed in an acidic aqueous liquid. The hydroxyethylcellulose Natrosol, available from Hercules Powder Company, 1-164 from Dowell, or WG-8 from Halliburton, are particularly suitable.

Generally suitable acidifying materials include acids or acidyielding materials that are adapted to be dissolved or substantially homogeneously distributed in an aqueous solution of the cellulosic thickening material. The acidic materials preferably reduce the pH of the solution to at least as low as about 4.0. Suitable materials include mineral acids such as hydrochloric acid, organic acids such as'formic acid, hydrolyzable esters of organic acids such as methyl formate, hydrolyzable organic halides such as tertiarybutylchloride, etc. For relatively low temperature or short-time temperature exposures, acids such" as hydrochloric acid or formic acid are particularly suitable. For relatively higher temperatures or longer time-temperature exposures, esters such as methyl format' are particularly suitable.

Generally suitable pH-increasing materials include compounds or mixtures of compounds that react with water, or react in the presence of water, to form watersoluble reaction products that increase the pH of an acidic aqueous solution by neutralizing or spending the acidity of the solution. Such materials include: amides of carbamic acid, urea, the homologues of urea, the salts of cyanic acid, organic acid amides such as formamide, dimethylformamide, acetamide, etc. Urea and the-lower organic amides, such as formamide and acetamide, or the like, are particularly suitable. In various situations, the present thickened aqueous liquids can comprise either a solution or a substantially homogeneous emulsion or dispersion of the acidifying and pH- increasing materials and the aqueous liquid solution of cellulosic material, as long as the components are substantially homogeneously distributed in that solution so that each portion of the solution contains a substantially equivalent proportion of each reactant.

In general, the concentration of the cellulosic material thickener in the aqueous solution can be varied substantially as desired to obtain the selected degree of viscosity. The proportion of dissolved cellulose material can range from about 0.1 to 4 percent by weight of the solution to provide viscosities which (at normal surface temperatures of about 80F) range from about 100 to 51,000 centipoise.

The amount and composition of the acidifying material is adjusted to be sufficient to cause a substantially complete breaking of the solution viscosity (preferably to a viscosity near that of water) after a selected timetemperature exposure of the solution. As known to those skilled in the art, increases in the amount of acid that is initially dissolved in the'solution, or increases in the rate at which the acid is formed within the solution, or increases in the strength of the acid (e.g., using a strong acid such as hydrochloric acid, or a relatively weak acid such as formic acid, or a mixture of strong and weak acids rather than using only a weak acid) decrease the amount of time-temperature exposure that is needed to induce the viscosity-breaking. The present thickened aqueous liquids can be formulated to break after times such as from about 4-24 hours after being pumped into a subterranean zone having a temperature of from about 100300F.

The amount and composition of the pI-I-increasing material is adjusted to ultimately raise the pH of the solution to a selected substantially neutral value. As known to those skilled in the art, the rate of the pH- increasing is affected by the composition and concentration of the pI-I-increasing reactant. The rate should be adjusted to allow sufficient acidity to remain (or be developed) in the aqueous solution of cellulosic material to cause the desired viscosity-breaking and subsequently raise the pH to the selected value, within a selected additional time at the temperature of the zone being treated. Where desired, the amount of the pH- increasing material can be sufficient to ultimately provide a solution pH of 7 (a neutral solution) or more (an alkaline solution). Since the acid-induced hydrolysis of the cellulosic material does not spend or neutralize the acid, where a complete neutralization is desired the proportions of acidizing and pI-I-increasing materials should' include at least a stoichiometric equivalent of the pI-I-increasing reactant. In addition, the pH- increasing reactant can be arranged to form a buffered solution that attains and maintains a selected pH, such as one from about 4 to 6. Such a pH-buffering can advantageously be obtained by the combination of reactants, such as urea and acetamide that provide a mixture of a weak acid and a soluble salt of a weak acid (i.e., a buffer system). v

The thickened aqueous liquids of the present invention can also contain substantially any of the conventionally used additives for packing or fracturing fluids. Such additives commonly include density-increasing salts, corrosion inhititors, wetting agents, etc. Such additives are suitable as long as they are compatible with the cellulosic thickener, acidic breaker and .pH- increasing reactants. Suitable weight-imparting salts include the monovalent metal or ammonium chlorides, such as 15% wt. solutions of ammoniumor potassium chloride. The use of ammonium chloride isparticularly preferred where the thickened liquid may be preceded or followed by a mud acid.

FIGS. 1 and 2 show a particularly advantageous utilization of the present invention. A well borehole l is equipped with a string of casing 2 that is surrounded by cement 3 and penetrated by perforations 4 within a subterranean reservoir 6. The casing is equipped with an internal pipe string 7 associated with a packing device 8, a fluid crossover means 9, a screening or filtering device 11, and a check valve means 12. The borehole equipment can comprise devices that are commercially available. Such equipment is preferably arranged for an injection of fluid into a subterranean reservoir as shown by the arrows.

. In accordance with the invention, a sand or gravel pack 13 is emplaced within the perforations, the associated perforation, tunnels (and/or voids) in the adjacent reservoir, and the annular space between the screen 11 and the casing 2 (as shown in FIG. 2). The packing granules are emplaced by suspending them in a selfthinning and neutralizing solution of the present invention and pumping the suspension into the well (preferably as shownby the arrows in FIG. 1.) until the grains are screened out against the face of the reservoir. As known to those skilled in the art, such a sand-out is identifiable by a significant increase in the fluid injection pressure, and usually occurs when much of the space between the pipe string 7 and the casing 2 is filled with the suspension.

After the selected time-temperature exposure, the viscosity of the present self-thinning fluid breaks and allows the suspended grains to settle. Subsequently, that fluid, of which a significant portion may remain in the space between the tubing and casing, becomes a self-neutralized static liquid 14 (see FIG. 2). Such a self-neutralization is particularly advantageous. When fluid is produced from the reservoir, it tends to flow directly through the screen 11 into the pipe string 7, (as shown by the arrows in FIG. 2), without displacing the substantially .static fluid in the annulus between the pipe string and the casing. If such a static fluid contains unneutralized acid, or contains an unreacted excess of oxidizing agent, it can be relatively corrosive and can damage the casing and cause a loss of the well.

The injection of a suspension of gravel packing grains is often preceded by injecting a slug of acid to increase the reservoir permeability. In such a procedure, a slug of viscous brine can be positioned between the acid and the suspension in order to keep the grainsuspending slurry from contacting the acid. It is desirable to ensure that all of the perforation tunnels and/or voids within the reservoir are completely and tightly packed. Therefore, reltively high pressures and large volumes of fluid are' often used to force a significant amount of fluid through the packing grains that are screened out against the face of thereservoir. This displaces a sign ificant portion of the grain suspending liquid into the reservoir in a zone surrounding the well from which fluids will be produced when the well (if it is a production well) is returned ,to-production.

In a particularly preferred embodiment of the present invention, the liquid in which the packed grains are suspended (i.e., thepresent self-thinning and neutralizing nium chloride, sodium chloride, or the like. In this embodiment it is thus ensured that (when the well being treated is an oil well) substantially all of the aqueous fluids which are mingled with the reservoir oil have a selected substantially neutral pH. This avoids an acid upset, due to the formation of an emulsion. Such emulsions are formed when various reservoir crudes, such as those encountered near the Gulf of Mexico, are mingled with relatively strongly acidic aqueous liquids.

FIG. 3 shows the effects of time at various temperatures on (1) an aqueous solution of 80 pounds of hydroxyethylcellulose (I-IEC) per 100 gallons of water, grams per liter potassium chloride, 2 moles per liter of methyl formate, and 0.1 pound per barrel of sodium hydroxide, and (2') an otherwise similar (but unacidified) HEC solution that contained no methyl formate. In an aqueous solution, methyl formate hydrolyzes to formic acid and methyl alcohol. And, the hydrolysis reaction is acid-catalyzed. As shown by FIG. 3., the solutions containing methyl formate and HEC are hydrolyzed at increasingly rapid rates and undergo increasingly rapid decreases in viscosity.

At 180F, the viscosity of the non-acidified 80-pound per 1,000 gallon I-IEC solution (about 8% by weight HEC) decreased slowly; by only about 50% in about 36 hours. In contrast, when a similar solution contained 2 moles of methyl formate, its viscosity was reduced by 99% in about 9 hours, and became as low as about 1 centipoise in about 24 hours. At lower temperatures, longer times are required to obtain the viscositybreak, due to the decreased rate of hydrolysis of both the methyl formate and the hydroxyethylcellulose. As indicated by the pH curves for the methyl formatecontaining solutions at 140 and 160F, a significant acceleration in viscosity reduction does not occur until the solution pH becomes less than about 2.5. Such tests, in the light of field experience, have indicated the suitability of acidifying materials including dilute I-ICl, formic acid, acetic-acid and methyl formate, for inducing the viscosity breaking for treatments conducted at temperatures of from about 110 to 200F. Field experience has shown that the relatively rapid viscosity breaking reactions, such as those of HCl, at temperatures above about 130F, cause substantially no problem in treating reservoirs at significantly higher temperatures. The available variations in pumping times, preinjections of relatively cool fluid, etc., were found to be sufficient for ensuring that the slurries were emplaced before their viscosities were reduced.

The following exemplifies a process of gravel packing an oil production well, where the reservoir being treated is about 7,500 feet deep, is about feet thick, and has a temperature of about 150F. The well is preferably equipped as shown in FIG. 1. The first solution injected is a pretreatment slug of about 1,000 gallons of an aqueous solution of 7.5% hydrochloric acid and 1.5% hydrofluoric acid, 1.65 moles per liter of urea and 1.5 moles per liter of acetamide. The acid preflush is followed by a buffer slug of about 2 barrels of 3% of ammonium chloride in water. The buffer slug is followed by about 3 barrels of a self-thinning and neutralizing brine containing about 8% by weight hydroxyethylcellulose solution, 1 mole per miter of hydrochloric acid, 1 mole per liter of urea, and 1.5 mole per liter of acetamide. The self-thinning and neutralizing brine solution is followed by about 10-12 barrels of a pack slurry comprising the same self-neutralizing and thinning solution in which there is suspended about 15 pounds per gallon of 2040 mesh gravel pack sand. The pack slurry is displaced ahead of an amount of aqueous brine sufficient to move its rear edge through the packer 8 and into the space between the pipe string 7 and the casing 2. The so-treated well is allowed to stand for about 24 hours and then returned to production.

What is claimed is:

1. A well treating process which comprises:

determining the approximate time and temperature to which a fluid will be subjected when the fluid has a selected viscosity and is pumped at a selected rate to a zone to be treated within the well; compounding an aqueous liquid that contains (a) enough dissolved acid-reactive cellulosic water thickener to provide the selected viscosity, (b) an amount and composition of substantially homogeneously distributed acidifying material sufficient to cause a decrease in the solution viscosity at a selected time after the solution reach'es said zone when pumped at said rate; and (c) an amount of substantially homogeneously distributed relatively slowly reactive pH-increasing material sufficient to raise the pH of the solution to a selected substantially neutral value within a selected additional time; and

pumping the compounded aqueous liquid into the well at a rate substantially equalling the selected rate.

2. The process of claim 1 in which a sand or gravel pack is formed by suspending packing grains in the compounded aqueous liquid before it is pumped into the well.

3. The process of claim 2 in which said acidifying material and pH increasing material are dissolved in said aqueous solution of cellulosic material.

4. The process of claim 2 in which the injection of the aqueous liquid containing the suspended grains is preceded by an injection of a slug of acid ahead of a slug of said compounded aqueous liquid that is free of suspended grains.

5. The process of claim 1 in which said acidifying and pH-increasing materials are, respectively, hydrochloric acid and a mixture of acetamide and urea.

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US3378070 *Sep 3, 1965Apr 16, 1968Halliburton CoHydroxyethyl cellulose complex and method of plugging underground formations therewith
US3415318 *Jun 28, 1967Dec 10, 1968Shell Oil CoMethod of curing loss of circulation of a fluid used in drilling a hole in an underground formation
US3826312 *Jul 24, 1972Jul 30, 1974Shell Oil CoSelf-neutralizing well acidizing
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4026361 *Jun 14, 1976May 31, 1977Shell Oil CompanyTreating wells with a temporarily thickening cellulose ether solution
US4122896 *Oct 14, 1977Oct 31, 1978Shell Oil CompanyAcidizing carbonate reservoirs with chlorocarboxylic acid salt solutions
US4219083 *Apr 6, 1979Aug 26, 1980Shell Oil CompanyNitrogen gas-generating reactants, reaction-retarding alkaline buffer, ph-reducing reactant
US4352396 *Nov 20, 1980Oct 5, 1982Getty Oil CompanyWater insoluble, oil soluble resin, water soluble ester and acid sensitive emulsifier
US4487265 *Dec 22, 1981Dec 11, 1984Union Oil Company Of CaliforniaAcidizing a subterranean reservoir
US4504400 *Jan 9, 1984Mar 12, 1985The Dow Chemical CompanyWater, hydroxyalkyl cellulose, fluoboric acid, hydrochloric acid
US4567946 *Jun 13, 1984Feb 4, 1986Union Oil Company Of CaliforniaIncreasing the permeability of a subterranean reservoir
US4617994 *Nov 22, 1985Oct 21, 1986Shell Oil CompanyDetermining residual oil saturation by injecting CO2 and base generating reactant
US4957163 *Jan 8, 1990Sep 18, 1990Texaco Inc.Method of stabilizing polymer solutions in a subterranean formation
US5082056 *Oct 16, 1990Jan 21, 1992Marathon Oil CompanyIn situ reversible crosslinked polymer gel used in hydrocarbon recovery applications
US6883608 *Aug 20, 2003Apr 26, 2005Schlumberger Technology CorporationGravel packing method
US7178594Jul 13, 2004Feb 20, 2007M-I L.L.C.Gravel packing a downhole area with a mixture including an alkoxylated fatty amine or polyalkyleneamine surfactant; emulsion can be converted from a water-in-oil to an oil-in-water type emulsion and back again upon protonation and deprotonation
US7373978Dec 18, 2003May 20, 2008Exxonmobil Upstream Research CompanyMethod for drilling and completing wells
US7661476Nov 9, 2007Feb 16, 2010Exxonmobil Upstream Research CompanyGravel packing methods
US7971642Feb 12, 2010Jul 5, 2011Exxonmobil Upstream Research CompanyGravel packing methods
US20100311621 *Jun 4, 2010Dec 9, 2010Rhodia OperationsMethods and compositions for viscosifying heavy aqueous brines
DE4410959A1 *Mar 29, 1994Oct 5, 1995Siemens AgStarting method for slip-ring induction motor for crane drive
DE4410959C2 *Mar 29, 1994Apr 15, 1999Siemens AgVerfahren zum Anlassen eines Schleifringläufermotors
EP0287727A1 *Apr 24, 1987Oct 26, 1988Union Oil Company Of CaliforniaGroundwater pollution abatement
Classifications
U.S. Classification166/250.1, 166/300, 166/278, 166/307
International ClassificationC09K8/90, E21B47/00, E21B43/04
Cooperative ClassificationC09K8/90, E21B43/045, E21B47/00
European ClassificationC09K8/90, E21B43/04C, E21B47/00