US3892275A - Self-thinning and neutralizing thickened aqueous liquid - Google Patents
Self-thinning and neutralizing thickened aqueous liquid Download PDFInfo
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- US3892275A US3892275A US436290A US43629074A US3892275A US 3892275 A US3892275 A US 3892275A US 436290 A US436290 A US 436290A US 43629074 A US43629074 A US 43629074A US 3892275 A US3892275 A US 3892275A
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- 239000007788 liquid Substances 0.000 title claims abstract description 28
- 230000003472 neutralizing effect Effects 0.000 title description 6
- 239000000463 material Substances 0.000 claims abstract description 45
- 239000000243 solution Substances 0.000 claims abstract description 43
- 239000007864 aqueous solution Substances 0.000 claims abstract description 14
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims abstract description 14
- 238000012856 packing Methods 0.000 claims abstract description 11
- 230000007423 decrease Effects 0.000 claims abstract description 8
- 239000002253 acid Substances 0.000 claims description 26
- 239000012530 fluid Substances 0.000 claims description 22
- 238000000034 method Methods 0.000 claims description 18
- 230000008569 process Effects 0.000 claims description 17
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 15
- 239000000203 mixture Substances 0.000 claims description 15
- DLFVBJFMPXGRIB-UHFFFAOYSA-N Acetamide Chemical compound CC(N)=O DLFVBJFMPXGRIB-UHFFFAOYSA-N 0.000 claims description 14
- 239000002562 thickening agent Substances 0.000 claims description 9
- XSQUKJJJFZCRTK-UHFFFAOYSA-N Urea Chemical compound NC(N)=O XSQUKJJJFZCRTK-UHFFFAOYSA-N 0.000 claims description 8
- 239000004202 carbamide Substances 0.000 claims description 8
- 238000002347 injection Methods 0.000 claims description 7
- 239000007924 injection Substances 0.000 claims description 7
- 239000004576 sand Substances 0.000 claims description 5
- 238000013329 compounding Methods 0.000 claims description 3
- 230000008719 thickening Effects 0.000 abstract description 4
- 239000002245 particle Substances 0.000 abstract description 2
- TZIHFWKZFHZASV-UHFFFAOYSA-N methyl formate Chemical compound COC=O TZIHFWKZFHZASV-UHFFFAOYSA-N 0.000 description 19
- 229920000663 Hydroxyethyl cellulose Polymers 0.000 description 11
- BDAGIHXWWSANSR-UHFFFAOYSA-N methanoic acid Natural products OC=O BDAGIHXWWSANSR-UHFFFAOYSA-N 0.000 description 10
- 230000002378 acidificating effect Effects 0.000 description 7
- 235000019447 hydroxyethyl cellulose Nutrition 0.000 description 7
- 230000007935 neutral effect Effects 0.000 description 7
- 239000000376 reactant Substances 0.000 description 7
- 239000004354 Hydroxyethyl cellulose Substances 0.000 description 6
- OSWFIVFLDKOXQC-UHFFFAOYSA-N 4-(3-methoxyphenyl)aniline Chemical compound COC1=CC=CC(C=2C=CC(N)=CC=2)=C1 OSWFIVFLDKOXQC-UHFFFAOYSA-N 0.000 description 5
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical class [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 description 5
- 235000019253 formic acid Nutrition 0.000 description 5
- 238000006460 hydrolysis reaction Methods 0.000 description 5
- ZHNUHDYFZUAESO-UHFFFAOYSA-N Formamide Chemical compound NC=O ZHNUHDYFZUAESO-UHFFFAOYSA-N 0.000 description 4
- WCUXLLCKKVVCTQ-UHFFFAOYSA-M Potassium chloride Chemical compound [Cl-].[K+] WCUXLLCKKVVCTQ-UHFFFAOYSA-M 0.000 description 4
- 150000007513 acids Chemical class 0.000 description 4
- 239000012267 brine Substances 0.000 description 4
- 229920002678 cellulose Polymers 0.000 description 4
- 239000001913 cellulose Substances 0.000 description 4
- 230000007062 hydrolysis Effects 0.000 description 4
- 238000004519 manufacturing process Methods 0.000 description 4
- 238000005086 pumping Methods 0.000 description 4
- 150000003839 salts Chemical class 0.000 description 4
- 239000002002 slurry Substances 0.000 description 4
- HPALAKNZSZLMCH-UHFFFAOYSA-M sodium;chloride;hydrate Chemical compound O.[Na+].[Cl-] HPALAKNZSZLMCH-UHFFFAOYSA-M 0.000 description 4
- 239000000725 suspension Substances 0.000 description 4
- QTBSBXVTEAMEQO-UHFFFAOYSA-N Acetic acid Chemical compound CC(O)=O QTBSBXVTEAMEQO-UHFFFAOYSA-N 0.000 description 3
- OKKJLVBELUTLKV-UHFFFAOYSA-N Methanol Chemical compound OC OKKJLVBELUTLKV-UHFFFAOYSA-N 0.000 description 3
- ZMXDDKWLCZADIW-UHFFFAOYSA-N N,N-Dimethylformamide Chemical compound CN(C)C=O ZMXDDKWLCZADIW-UHFFFAOYSA-N 0.000 description 3
- HEMHJVSKTPXQMS-UHFFFAOYSA-M Sodium hydroxide Chemical compound [OH-].[Na+] HEMHJVSKTPXQMS-UHFFFAOYSA-M 0.000 description 3
- 239000000654 additive Substances 0.000 description 3
- -1 alkaline earth metal salts Chemical class 0.000 description 3
- 235000019270 ammonium chloride Nutrition 0.000 description 3
- 239000000839 emulsion Substances 0.000 description 3
- 150000007524 organic acids Chemical class 0.000 description 3
- 230000003068 static effect Effects 0.000 description 3
- 229920002134 Carboxymethyl cellulose Polymers 0.000 description 2
- KRHYYFGTRYWZRS-UHFFFAOYSA-N Fluorane Chemical compound F KRHYYFGTRYWZRS-UHFFFAOYSA-N 0.000 description 2
- FAPWRFPIFSIZLT-UHFFFAOYSA-M Sodium chloride Chemical compound [Na+].[Cl-] FAPWRFPIFSIZLT-UHFFFAOYSA-M 0.000 description 2
- 230000009471 action Effects 0.000 description 2
- 239000000872 buffer Substances 0.000 description 2
- 239000001768 carboxy methyl cellulose Substances 0.000 description 2
- 235000010948 carboxy methyl cellulose Nutrition 0.000 description 2
- 239000008112 carboxymethyl-cellulose Substances 0.000 description 2
- 229920003086 cellulose ether Polymers 0.000 description 2
- 238000006243 chemical reaction Methods 0.000 description 2
- 150000001875 compounds Chemical class 0.000 description 2
- XLJMAIOERFSOGZ-UHFFFAOYSA-N cyanic acid Chemical class OC#N XLJMAIOERFSOGZ-UHFFFAOYSA-N 0.000 description 2
- 230000003247 decreasing effect Effects 0.000 description 2
- 150000002148 esters Chemical class 0.000 description 2
- 229940093915 gynecological organic acid Drugs 0.000 description 2
- 238000006386 neutralization reaction Methods 0.000 description 2
- 235000005985 organic acids Nutrition 0.000 description 2
- 230000001590 oxidative effect Effects 0.000 description 2
- 239000001103 potassium chloride Substances 0.000 description 2
- 235000011164 potassium chloride Nutrition 0.000 description 2
- VEXZGXHMUGYJMC-UHFFFAOYSA-M Chloride anion Chemical compound [Cl-] VEXZGXHMUGYJMC-UHFFFAOYSA-M 0.000 description 1
- 230000001133 acceleration Effects 0.000 description 1
- 235000011054 acetic acid Nutrition 0.000 description 1
- 229960000583 acetic acid Drugs 0.000 description 1
- 230000001476 alcoholic effect Effects 0.000 description 1
- 229910052784 alkaline earth metal Inorganic materials 0.000 description 1
- 239000012670 alkaline solution Substances 0.000 description 1
- 125000000217 alkyl group Chemical group 0.000 description 1
- 150000001408 amides Chemical class 0.000 description 1
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 1
- 230000015572 biosynthetic process Effects 0.000 description 1
- 239000007853 buffer solution Substances 0.000 description 1
- 239000008366 buffered solution Substances 0.000 description 1
- KXDHJXZQYSOELW-UHFFFAOYSA-N carbonic acid monoamide Natural products NC(O)=O KXDHJXZQYSOELW-UHFFFAOYSA-N 0.000 description 1
- 150000003857 carboxamides Chemical class 0.000 description 1
- 125000004181 carboxyalkyl group Chemical group 0.000 description 1
- 239000004568 cement Substances 0.000 description 1
- 239000007795 chemical reaction product Substances 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 239000006185 dispersion Substances 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000002255 enzymatic effect Effects 0.000 description 1
- 150000002170 ethers Chemical class 0.000 description 1
- 238000001914 filtration Methods 0.000 description 1
- 239000008187 granular material Substances 0.000 description 1
- 150000004820 halides Chemical class 0.000 description 1
- 230000001939 inductive effect Effects 0.000 description 1
- 229910052500 inorganic mineral Inorganic materials 0.000 description 1
- 239000006193 liquid solution Substances 0.000 description 1
- 229910052751 metal Inorganic materials 0.000 description 1
- 239000002184 metal Substances 0.000 description 1
- 229920000609 methyl cellulose Polymers 0.000 description 1
- 125000002496 methyl group Chemical group [H]C([H])([H])* 0.000 description 1
- 239000004292 methyl p-hydroxybenzoate Substances 0.000 description 1
- 239000001923 methylcellulose Substances 0.000 description 1
- 235000010981 methylcellulose Nutrition 0.000 description 1
- 239000011707 mineral Substances 0.000 description 1
- 235000010755 mineral Nutrition 0.000 description 1
- 230000009972 noncorrosive effect Effects 0.000 description 1
- 239000003129 oil well Substances 0.000 description 1
- 239000007800 oxidant agent Substances 0.000 description 1
- 239000001301 oxygen Substances 0.000 description 1
- 229910052760 oxygen Inorganic materials 0.000 description 1
- KHIWWQKSHDUIBK-UHFFFAOYSA-N periodic acid Chemical compound OI(=O)(=O)=O KHIWWQKSHDUIBK-UHFFFAOYSA-N 0.000 description 1
- 230000035699 permeability Effects 0.000 description 1
- 239000000047 product Substances 0.000 description 1
- 230000009467 reduction Effects 0.000 description 1
- 238000012216 screening Methods 0.000 description 1
- 239000011780 sodium chloride Substances 0.000 description 1
- NBRKLOOSMBRFMH-UHFFFAOYSA-N tert-butyl chloride Chemical compound CC(C)(C)Cl NBRKLOOSMBRFMH-UHFFFAOYSA-N 0.000 description 1
- KJAMZCVTJDTESW-UHFFFAOYSA-N tiracizine Chemical compound C1CC2=CC=CC=C2N(C(=O)CN(C)C)C2=CC(NC(=O)OCC)=CC=C21 KJAMZCVTJDTESW-UHFFFAOYSA-N 0.000 description 1
- 238000011282 treatment Methods 0.000 description 1
- 239000000080 wetting agent Substances 0.000 description 1
Images
Classifications
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- C—CHEMISTRY; METALLURGY
- C09—DYES; PAINTS; POLISHES; NATURAL RESINS; ADHESIVES; COMPOSITIONS NOT OTHERWISE PROVIDED FOR; APPLICATIONS OF MATERIALS NOT OTHERWISE PROVIDED FOR
- C09K—MATERIALS FOR MISCELLANEOUS APPLICATIONS, NOT PROVIDED FOR ELSEWHERE
- C09K8/00—Compositions for drilling of boreholes or wells; Compositions for treating boreholes or wells, e.g. for completion or for remedial operations
- C09K8/60—Compositions for stimulating production by acting on the underground formation
- C09K8/84—Compositions based on water or polar solvents
- C09K8/86—Compositions based on water or polar solvents containing organic compounds
- C09K8/88—Compositions based on water or polar solvents containing organic compounds macromolecular compounds
- C09K8/90—Compositions based on water or polar solvents containing organic compounds macromolecular compounds of natural origin, e.g. polysaccharides, cellulose
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/02—Subsoil filtering
- E21B43/04—Gravelling of wells
- E21B43/045—Crossover tools
Definitions
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- 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.
- acids such" as hydrochloric acid or formic acid are particularly suitable.
- esters such as methyl format' are particularly 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.
- 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.
- 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.
- 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
- 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.
- 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.
- 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).
- the proportions of acidizing and pI-I-increasing materials should' include at least a stoichiometric equivalent of the pI-I-increasing reactant.
- 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.
- 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).
- the thickened aqueous liquids of the present invention can also contain substantially any of the conventionally used additives for packing or fracturing fluids.
- 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.
- 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.
- 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.
- 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).
- a self-neutralization is particularly advantageous.
- fluid 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.
- a suspension of gravel packing grains is often preceded by injecting a slug of acid to increase the reservoir permeability.
- 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.
- the liquid in which the packed grains are suspended i.e., thepresent self-thinning and neutralizing nium chloride, sodium chloride, or the like.
- the liquid in which the packed grains are suspended i.e., thepresent self-thinning and neutralizing nium chloride, sodium chloride, or the like.
- 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.
- I-IEC hydroxyethylcellulose
- 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.
- methyl formate hydrolyzes to formic acid and methyl alcohol.
- the hydrolysis reaction is acid-catalyzed.
- the viscosity of the non-acidified 80-pound per 1,000 gallon I-IEC solution decreased slowly; by only about 50% in about 36 hours.
- 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.
- longer times are required to obtain the viscositybreak, due to the decreased rate of hydrolysis of both the methyl formate and the hydroxyethylcellulose.
- a significant acceleration in viscosity reduction does not occur until the solution pH becomes less than about 2.5.
- 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.
- a well treating process which comprises:
Abstract
A thickened aqueous liquid, suitable for suspending packing particles, comprises an aqueous solution containing an acidreactive 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.
Description
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.
Claims (5)
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 WITH 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
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.
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US436290A US3892275A (en) | 1974-01-24 | 1974-01-24 | Self-thinning and neutralizing thickened aqueous liquid |
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US4026361A (en) * | 1976-06-14 | 1977-05-31 | Shell Oil Company | Treating wells with a temporarily thickening cellulose ether solution |
US4122896A (en) * | 1977-10-14 | 1978-10-31 | Shell Oil Company | Acidizing carbonate reservoirs with chlorocarboxylic acid salt solutions |
US4219083A (en) * | 1979-04-06 | 1980-08-26 | Shell Oil Company | Chemical process for backsurging fluid through well casing perforations |
US4352396A (en) * | 1980-11-20 | 1982-10-05 | Getty Oil Company | Method for selective plugging using resin emulsions |
US4487265A (en) * | 1981-12-22 | 1984-12-11 | Union Oil Company Of California | Acidizing a subterranean reservoir |
US4504400A (en) * | 1981-10-02 | 1985-03-12 | The Dow Chemical Company | Fluid and method for placing gravel packs |
US4567946A (en) * | 1982-02-08 | 1986-02-04 | Union Oil Company Of California | Increasing the permeability of a subterranean reservoir |
NL8503065A (en) * | 1984-11-09 | 1986-06-02 | Shell Int Research | METHOD FOR DEGRADING A VISCOUS MICROBIAL POLYSACCHARIDE FORMULATION, A METHOD FOR PREPARING AN ACID-DEGRADABLE POLYSACCHARIDE FORMULATION, AND A POLYSACCHARIDE FORMULATION SO DERIVED. |
US4617994A (en) * | 1985-11-22 | 1986-10-21 | Shell Oil Company | Determining residual oil saturation by injecting CO2 and base generating reactant |
EP0287727A1 (en) * | 1987-04-24 | 1988-10-26 | Union Oil Company Of California | Groundwater pollution abatement |
US4957163A (en) * | 1990-01-08 | 1990-09-18 | Texaco Inc. | Method of stabilizing polymer solutions in a subterranean formation |
US5082056A (en) * | 1990-10-16 | 1992-01-21 | Marathon Oil Company | In situ reversible crosslinked polymer gel used in hydrocarbon recovery applications |
DE4410959A1 (en) * | 1994-03-29 | 1995-10-05 | Siemens Ag | Starting method for slip-ring induction motor for crane drive |
US20040259738A1 (en) * | 1996-08-02 | 2004-12-23 | Patel Arvind D. | Method for using reversible phase oil-based drilling fluid |
US20050028978A1 (en) * | 2003-08-06 | 2005-02-10 | Mehmet Parlar | Gravel packing method |
US20070068675A1 (en) * | 2003-02-26 | 2007-03-29 | Barry Michael D | Method for drilling and completing wells |
US20080128129A1 (en) * | 2006-11-15 | 2008-06-05 | Yeh Charles S | Gravel packing methods |
US20080214414A1 (en) * | 2005-07-22 | 2008-09-04 | Arkema Inc. | Organosulfonyl Latent Acids for Petroleum Well Acidizing |
US20100311621A1 (en) * | 2009-06-04 | 2010-12-09 | Rhodia Operations | Methods and compositions for viscosifying heavy aqueous brines |
AU2014203443A1 (en) * | 2013-07-31 | 2015-02-19 | Schlumberger Technology B.V. | Viscosified acid fluid and method for use thereof |
US9476287B2 (en) | 2013-11-05 | 2016-10-25 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
US9573808B2 (en) | 2013-07-31 | 2017-02-21 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
US9796490B2 (en) | 2013-10-24 | 2017-10-24 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
US9920606B2 (en) | 2013-07-31 | 2018-03-20 | Schlumberger Technology Corporation | Preparation method, formulation and application of chemically retarded mineral acid for oilfield use |
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Cited By (34)
Publication number | Priority date | Publication date | Assignee | Title |
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US4026361A (en) * | 1976-06-14 | 1977-05-31 | Shell Oil Company | Treating wells with a temporarily thickening cellulose ether solution |
US4122896A (en) * | 1977-10-14 | 1978-10-31 | Shell Oil Company | Acidizing carbonate reservoirs with chlorocarboxylic acid salt solutions |
US4219083A (en) * | 1979-04-06 | 1980-08-26 | Shell Oil Company | Chemical process for backsurging fluid through well casing perforations |
US4352396A (en) * | 1980-11-20 | 1982-10-05 | Getty Oil Company | Method for selective plugging using resin emulsions |
US4504400A (en) * | 1981-10-02 | 1985-03-12 | The Dow Chemical Company | Fluid and method for placing gravel packs |
US4487265A (en) * | 1981-12-22 | 1984-12-11 | Union Oil Company Of California | Acidizing a subterranean reservoir |
US4567946A (en) * | 1982-02-08 | 1986-02-04 | Union Oil Company Of California | Increasing the permeability of a subterranean reservoir |
NL8503065A (en) * | 1984-11-09 | 1986-06-02 | Shell Int Research | METHOD FOR DEGRADING A VISCOUS MICROBIAL POLYSACCHARIDE FORMULATION, A METHOD FOR PREPARING AN ACID-DEGRADABLE POLYSACCHARIDE FORMULATION, AND A POLYSACCHARIDE FORMULATION SO DERIVED. |
US4617994A (en) * | 1985-11-22 | 1986-10-21 | Shell Oil Company | Determining residual oil saturation by injecting CO2 and base generating reactant |
EP0287727A1 (en) * | 1987-04-24 | 1988-10-26 | Union Oil Company Of California | Groundwater pollution abatement |
US4957163A (en) * | 1990-01-08 | 1990-09-18 | Texaco Inc. | Method of stabilizing polymer solutions in a subterranean formation |
US5082056A (en) * | 1990-10-16 | 1992-01-21 | Marathon Oil Company | In situ reversible crosslinked polymer gel used in hydrocarbon recovery applications |
DE4410959A1 (en) * | 1994-03-29 | 1995-10-05 | Siemens Ag | Starting method for slip-ring induction motor for crane drive |
DE4410959C2 (en) * | 1994-03-29 | 1999-04-15 | Siemens Ag | Process for starting a slip ring motor |
US20040259738A1 (en) * | 1996-08-02 | 2004-12-23 | Patel Arvind D. | Method for using reversible phase oil-based drilling fluid |
US7178594B2 (en) | 1996-08-02 | 2007-02-20 | M-I L.L.C. | Method for using reversible phase oil-based drilling fluid |
US7373978B2 (en) | 2003-02-26 | 2008-05-20 | Exxonmobil Upstream Research Company | Method for drilling and completing wells |
US20070068675A1 (en) * | 2003-02-26 | 2007-03-29 | Barry Michael D | Method for drilling and completing wells |
US6883608B2 (en) * | 2003-08-06 | 2005-04-26 | Schlumberger Technology Corporation | Gravel packing method |
US20050028978A1 (en) * | 2003-08-06 | 2005-02-10 | Mehmet Parlar | Gravel packing method |
US20110136706A1 (en) * | 2005-07-22 | 2011-06-09 | Arkema Inc. | Organosulfonyl latent acids for petroleum well acidizing |
US20080214414A1 (en) * | 2005-07-22 | 2008-09-04 | Arkema Inc. | Organosulfonyl Latent Acids for Petroleum Well Acidizing |
US7661476B2 (en) | 2006-11-15 | 2010-02-16 | Exxonmobil Upstream Research Company | Gravel packing methods |
US20100139919A1 (en) * | 2006-11-15 | 2010-06-10 | Yeh Charles S | Gravel Packing Methods |
US20080128129A1 (en) * | 2006-11-15 | 2008-06-05 | Yeh Charles S | Gravel packing methods |
US7971642B2 (en) | 2006-11-15 | 2011-07-05 | Exxonmobil Upstream Research Company | Gravel packing methods |
US20100311621A1 (en) * | 2009-06-04 | 2010-12-09 | Rhodia Operations | Methods and compositions for viscosifying heavy aqueous brines |
US9062238B2 (en) * | 2009-06-04 | 2015-06-23 | Rhodia Operations | Methods and compositions for viscosifying heavy aqueous brines |
AU2014203443A1 (en) * | 2013-07-31 | 2015-02-19 | Schlumberger Technology B.V. | Viscosified acid fluid and method for use thereof |
AU2014203443B2 (en) * | 2013-07-31 | 2015-12-03 | Schlumberger Technology B.V. | Viscosified acid fluid and method for use thereof |
US9573808B2 (en) | 2013-07-31 | 2017-02-21 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
US9920606B2 (en) | 2013-07-31 | 2018-03-20 | Schlumberger Technology Corporation | Preparation method, formulation and application of chemically retarded mineral acid for oilfield use |
US9796490B2 (en) | 2013-10-24 | 2017-10-24 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
US9476287B2 (en) | 2013-11-05 | 2016-10-25 | Schlumberger Technology Corporation | Aqueous solution and method for use thereof |
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