CA1295119C - Method of increasing retention of scale inhibitor in subterranean formations - Google Patents
Method of increasing retention of scale inhibitor in subterranean formationsInfo
- Publication number
- CA1295119C CA1295119C CA000585305A CA585305A CA1295119C CA 1295119 C CA1295119 C CA 1295119C CA 000585305 A CA000585305 A CA 000585305A CA 585305 A CA585305 A CA 585305A CA 1295119 C CA1295119 C CA 1295119C
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- Prior art keywords
- acid
- inhibitor
- formation
- polyvalent cation
- polyacrylate
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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
- C09K8/52—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning
- C09K8/528—Compositions for preventing, limiting or eliminating depositions, e.g. for cleaning inorganic depositions, e.g. sulfates or carbonates
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- Chemical & Material Sciences (AREA)
- Inorganic Chemistry (AREA)
- Life Sciences & Earth Sciences (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Materials Engineering (AREA)
- Organic Chemistry (AREA)
- Addition Polymer Or Copolymer, Post-Treatments, Or Chemical Modifications (AREA)
- Geophysics And Detection Of Objects (AREA)
Abstract
METHOD OF INCREASING RETENTION OF SCALE INHIBITOR
IN SUBTERRANEAN FORMATIONS
ABSTRACT
A method for inhibiting the formation of scale in a well penetrating a subterranean formation for the production of fluids from the formation comprising injecting into the formation an acidic aqueous solution having a pH no greater than 3 containing a mixture of a polyacrylate scale inhibitor having a molecular weight range from 500 to 10,000 and a polyvalent cation wherein the equivalent ratio of polyvalent cation to polyacrylate scale inhibitor is less than or equal to 0.5 in the acidic aqueous solution and allowing natural conditions in the formation to raise the pH of the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The scale inhibitor solution employed in this method avoids premature plugging of the formation, substantially extends the life of the treatment and the polyvalent cation complex of the polyacrylate is fully inhibitive.
IN SUBTERRANEAN FORMATIONS
ABSTRACT
A method for inhibiting the formation of scale in a well penetrating a subterranean formation for the production of fluids from the formation comprising injecting into the formation an acidic aqueous solution having a pH no greater than 3 containing a mixture of a polyacrylate scale inhibitor having a molecular weight range from 500 to 10,000 and a polyvalent cation wherein the equivalent ratio of polyvalent cation to polyacrylate scale inhibitor is less than or equal to 0.5 in the acidic aqueous solution and allowing natural conditions in the formation to raise the pH of the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The scale inhibitor solution employed in this method avoids premature plugging of the formation, substantially extends the life of the treatment and the polyvalent cation complex of the polyacrylate is fully inhibitive.
Description
IOD OF INCREASING RETENTION OF SCALE IN~ ITOR
IN SUBTERRANFAN FO~TIONS
This invention relates to inhibitin~ scale formation in a well penetratin~ a subterranean formation and particularly a method for increasin~ retention of the scale inhibitor in the formation.
In the production of water7 oil and ~as from subterranean S formations, scale deposits can frequently result in: plug~ed well bores, plu~ed well casin~ perforations, plu~ed tubin~ strin~s, stuck downhole safety valves as well as other valves, stuck downhole pumps and other downhole and surface equipment and lines, scaled formations and fractures in the vicinity of the well. ~uch scale lo formation can occur as a result of mixin~ of incompatible waters in the well, i.e., waters which when mixed ~roduce precipitates, or as a result of temperature and pressure chan~es and the like in the produced waters durina production. Cenerally, incompatible waters are formed as a consequence of waterfloodin~, as injected sea water mixes with formation water in the borehole durin~ water breakthrou~h. The more common concern is scales deposited because of chan~es in supersaturation or solubility of minerals in the formation or produced waters caused by pressure and temperature chan~es, or changes in other physical and chemical environments such as ~as compositions, ratio of gas/oil/water. Precipitation frequently encountered as scale include calcium carbonate, calcium sulfate, barium sulfate, ma~nesium carbonate, ma~nesium sulfate, and strontium sulfate. The deposition of scale is a very complex crystalline process initiated by a supersaturation-induced nucleation of a precipitate of the mineral, scale ions contact these nuclei and the crystal ~rows in a certain cr~stalline pattern. Ihe adherence of these mineral crystals unto the formation matrix, perforation, well-bore, tubin~s and equipment is a not well-understood process but once initiated, appears to be F-~1619 --2-~
spontaneous as seen by the increasin~ thickness of the scale deposit and the steady decline in productivity. In some cases, production can be halted when valves and pumps are stuck -- creatin~ a potentially dangerous situation. The normal practice of treatin~
with inhibitors does protect scales from formin~ in the perforations or near well-bore areas, well tubulars, downhole pump, other downhole equipment9 and surface equipment. B~t such practice results in very short life requirin~ frequent re-treatments and necessitating periods of loss of pr~duction. A siqni~icant extension of life means that down-times due to re-treatments will be much less frequent translating to better economics of operation.
The squeezin~ of chemicals for protectin~ wells, particularly oil wells, is widely practiced. A "squeeze" ,ob mi~ht last one to six months depending on the nature of the subterranean formation into which the chemical is squeezed and the rate at which fluids e.g., oil and water, are produced by the well. A formation that has low permeability but hi~h porosity, and from which low rates of oil and water are produced would likely bleed injected chemicals back for a long time. However, a problem arises with hi~hly permeable formations which produce hi~h rates of oil and water. This type of formation retains chemicals for only a short time because they are readily washed out of the permeable zones of the formation by the hi~h volumes of produced fluids. The inhibitor is normally retained by an adsorption mechanism into the formation matrix and released by desorption durin~ fluids production. In ~eneral, at least a third or more of the inhibitor is not absorbed but is immediately produced back, resultin~ in ineffective use and frequent retreatments.
In an article by Carlber~ and Essel entitled, "Strontium S~1lfate Scale Control by Inhibitor Squeeze Treatment in the Fateh Field", published in the Journal of Petroleum Technolo~y, in June 19~2, there is disclosed a method for inhibitin~ scale formation in a subterranean limestone formation by injectin~ an acid form of a polyphosphonate which forms a sli~htly soluble calcium salt.
. .
~-4619 Calcium ions released on dissolution of some of the limestone (calcium carbonate) rock by the acid precipitates calcium polyphosphonate allowing ~reater retention in the rock. However, this method does not work in sandstones, because sandstones are not soluble in acids, nor do they form calcium ions even when dissolved.
U.S. Patent 3,827,977 to L.~l. Miles and G.F. Kin~, issued Aug. 6, ~97~, discloses a method of increasing retention of an inhibitor by in situ formation of the relatively water or brine insoluble polycation salt of polyacrylic acid or hydrolyzed polyacrylamide. A stron~ acid solution used initially inhibits reaction of the salts but the acid is eventually neutrallzed by the formation rock allowing the deposition of the water insoluble metal salt of the inhibitor in the formation. In the practice of the Miles et al invention, a larger than stoichiometric amount of the polyvalent metal salt (with Ca 2 and zn~2 preferred) associated with the carboxylic acids ~roups of the inhibitor is required to insure complete reaction of the inhibitor (i.e., equivalent ratio cf polyvalent metal cation to carboxyl;c acids ~reater than 1.0). For example, Miles et al cites a concentration of about 0.5 to 1.5%
solutions by weight Ca with 0.5 to 1% solutions of the sodium polyacrylate. Assumin~ a molecular wei~ht of 5000 for the polyacrylate (at 1% by weight) and Ca 2 at 0.5 %, the equivalent ratio of Ca to carboxylic acid ~roups is 1.8; while the mole ratio of Ca to polyacrylate is 62.5. The limiting factor in the use of such high concentrations of multivalent metal ions is the danger of dama~ing the formation by plugging it with premature precipitation.
In an article by KØ ~eyers et al, entitled "Control of Formation ~amage at Prudhoe Pay, AK, by Inhibitor Squeeze Treatment", published in the Journal of Pet. Tech., pp 26, in June 1985, they caution against the presence of high concentrations of calcium when the inhibitor is s~ueezed into a well for the same reason. The normal criteria for selection of an inhibitor includes having hi~h solubility in the reservoir brine and low susceptibility to precipitation by divalent cations. Therefore, introduction of the inhibitor in the manner tauaht by ~qiles et al affords little or no protection in inhibitin~ premature precipitation that causes plu~in~ of the formation.
According to the present invention the danger of dama~in~
the formation by precipitation is avoided by limitin~ the equivalent ratio of multivalent cations to inhibitor to a ratio of 0.5 or less and limitin~ inhibitor molecular wei~ht ran~e to 500 to 10,000 which extends the life of the polyacrylate inhibitor 2 to 5 times that of a similar treatment without the polyvalent cation. Furthermore, at these low polyvalent cation concentrations, the polyacrylic inhibitor is very active while the activity is dim nished si~nificantly at a high polyvalent cation concentration (equivalent ratio ~reater than 0.5)0 The present invention proYides for a method for inhibitin~
scale in a well penetrating a subterranean formation for the production of fluids from the formati~n comprising dissolvin~ a polymeric inhibitor comprising an alpha, beta-ethylenically unsaturated carboxylic acid havin~ a molecular wei~ht of 500 to 10,000 and a polyvalent cation in a aqueous solution having a p~ not greater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate inhibitor is less than or equal to 0.5 and injecting the polyacrylate inhibitor, polyvalent cation aqueous solution into the formation about the well and allowin~ natural conditions in the formations to raise the pl-l of -the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The polyvalent cation comprises any cation with a valence of two or greater, preferably Cr 3, Ti 3, Al 3, Fe 3 or Zr ~ in the form of a water-soluble salt. ~uitable polymeric inhibitors include all homopolymers or copolymers (composed of two or more co-monomers) containing as one of its components, an alpha beta-ethylenically unsaturated acid monomer such as acrylic acid, methacrylic acid, diacids such as maleic acid (or maleic anhydride), F-4619 ~~5 ~
itaconic acid, fumaric acid, mesaconic acid, citraconic acid and the like, monoesters of diacids with alkanols having 1-8. carbon atoms, and mixtures thereof. For simplicity, these acid monomers shall henceforth be called acrylic monomers. When the inhibitor is a copolymer, the other component monomers can be any alpha, beta-ethylenically unsaturated monomer with either a non-polar group such as styrene or olefinic monomers or a polar functional ~roups such as vinylacetate, vinyl chloride, vinyl alcohol, acrylate ester, vinylpyridine, vinyl pyrrolidone, acrylamide or acrylamide derivatives, etc., or with ionic functional ~roups such as styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (A~S), vinylsulfonic acid, vinylphosphonic acid. The polyacrylate inhibitor includes modification of the polymers described above such as phosphino-polyacrylic acid sold under the trade mark "B2lsperse 161" or "Belasol S-29" by Ciba Gei~y. The preferred polyacrylate inhibitor is phosphino-polyacrylic acid.
Fi~. 1 illustratcs the concentration (ppm) of inhibitor in produced water versus pore volume of back-produced water for a 2000 ppm inhibitor solution of'~elsperse 161"
Fig. 2 illustrates the concentration (ppm) of inhibitor in produced water versus pore volume of back-pro~lced water for a 2000 ppm inhibitor solution of'~elsperse 161"and 22 ppm Cr 3 (equivalent ratio = 0.045).
In accordance with the present invention, a subterranean formation is penetrated by a wellbore, includin~ a casin~ in f~uid communication therewith by means of well casing perforations in the zone of the formation. Production occurs from the formation by the flow of fluids includln~ oil, gas and water throu~h the perforations into the well bore with the fluids then being recovered. The production of fluids from the well can be inhibited by the formation of scale which plugs or partially plu~s perforations in the casing of the wellbore, tubin~ inside the casing, downhole equipment such as pumps and safety valves or the formation near the well.
~-4619 --6--In the present invention, a polyacrylate scale inhibitor havin~ a molecular wei~ht range from 500 to 10,000 and a polyvalent cation are dissolved in an acidic aqueous solution havin~ a pH not ~reater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate is equal to or less than 0.5. Suitable cations are any cations with a valence of 2 or ~reater, preferably Cr 3, Ti 3, A1~3, Fe 3 and Zr 4, in the form of a water-soluble salt.
Generally any stron~ acid or mixtures of stron~ and weak acids can be used to prepare the acidic aqueous solution. Sulfuric acid should not be used for this purpose because the sulfate ions present scale problems. Sui-table polyacrylate inhibitors include all homopolymers or copolymers (composed of two or more co-monomers) containin~ as one of its components, an alpha, beta-ethylenically unsaturated acid monomer such as acrylic acid, methacrylic acid, diacids such as maleic acid (or maleic anhydride), itaconic acid, fumaric acid, mesaconic acid, citraconic acid and the like, monoesters of diacids with alkanols havin~ carbon atoms, and mixtures thereof. For simplicity, these acid monomers shall henceforth be called acrylic monomers. When the inhibitor is a copolymer, the other component monomers can be any alpha, beta-ethylenically unsaturated monomer with either a non-polar ~roup such as styrene or olefinic monomers, or a polar functional ~roup such as vinylacetate, vinyl chloride, ~inyl alcohol, acrylate ester, vinyl pyridine, vinyl pyrrolidone, acrylamide or acrylamide derivatives, etc., or with ionic functional ~roup such as styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (AMPS), vinylsulfonic acid, vinylphosphonic acid. The polyacrylate inhibitor includes modification of the polymers described above such as phosphino-polyacrylic acid sold under ~he trade mark "Belsperse 161" or "Belasol S-29" by Ciba Gei~y, The molecular wei~ht ran~e of the polyacrylate inhibitor utilized in this invention is from 500 to 10,000. ~s the inhibitor molecular wei~ht increases, there is ~reater suceptibility towards uncontrolled precipitation and dama~e to the formation and well-bore. The selection of the scale ~-~619 `~7~~
inhibitor is hiFhly dependent upon the characteristics of the formation, the composition, and other environmental factors. As acidic aqueous solution containin~ a polyacrylate inhibitor and a polycation is injected, the acid prevents any premature precipitation or insolubilization by allowing the polycation to form a water-soluble complex with the inhibitor. Upon enterin~ the formation the acid is dissipated and the natural conditions in the formation raises the pH of the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The solution containin~ the complexed scale inhibitor is retained in the form~tion and slowly released from the formation ~ith the produced aqueous fluids as the well is produced thereby inhibitin~ formation of chan~in~ scale deposits in the formation in the vicinity of the wellbore, casin~ perforations, tubin~ and other downhole equipment as well as corrosion in the well. Generally, ir,jection of the aqueous acid solution of polyacrylate and polyvalent cation is desi~nated to extend at least several inches, 3 or 4, (7.5 to 10 cm) to several feet, 3 or 4, or more, (1 to 1.3~, or more) from the wellbore. In ~eneral, an amount of inhibitor solution is injected into the formation surroundin~ the oil well that is sufficient to feed back a concentration of the inhibitor effective to prevent the formation of scale deposits. The acidic aqueous solution of polyvalent cations and polyacrylate may be driven to ~reater radial distances by usinF a waterflood of water, oil or Fas to assure that the scale inhibitor will be exposed and retained to a much ~reater surface area in the producin~
formations. Typically, the effective concentration of inhibitor bein~ fed back is in the ran~e of 0.05 to 50 ppm and preferably 0.5 to 10 ppm in the produced water. The exact quantity of inhibitor solution used for a treatment is dependent on a number of factors unique to the well that is bein~ treated. These factors include:
the de~ree of supersaturation expected of the scale formin~ minerals in the produced water~ the rate of production of water, temperature and pressure profile in the well, the len~th of protection desired which is related to the radial distance reached by the inhibitor treatment, and others. The concentration of polyacrylate inhibitor employed in the acidic aqueous solution can vary from 0.1 to 20.0 percent by wei~ht in fresh water, sea water or other available brines, but preferably in the 0.5 to 5.0 percent by weight range.
After the scale inhibitor has been deposited into the formation, production of fluids including oil and ~ater from the well is resumed. The scale inhihitor is released slowly at lo effective concentration to inhibit scale formation or corrosion for a substantial period of time. The scale treatment of this invention may be repeated on a regular basis based on experience or when the che~ical return concentration falls below minimum requirements or when other scale formin~ indicators indicate that additional treatment should be applied.
Phosphino-polyacrylic acid with an average molecular wei~ht of 1000 to 1200 sold under the trademark "~elsperse 161" or "Belasol ~-Z9" by Ciba Geigy is a very versatile inhibitor for treatmeot of sulfate and carbonate scales. '~elsperse 161"is used here as a ~odel inhibitor to demonstrate the concept. Cr 3 (from CrC13~ 6 H2O) is used as an example of a polyvalent cation.
Example 1 The effect of Cr 3 concentration on the inhibition of barium sulfate by'~elsperse 161"was investi~ated. In each case, 2 cc of a simulated sea water containing Cr 3 and the inhibitor was mixed with 8 cc of a simulated connate water (or formation water;
water native to the reservoir) and observed visually for precipitation of bariu~ sulfate after standing for 20 hours at 24C. The results shown in Table 1 indicate excellent inhibition at 4 ppm of'~elsperse 161"with 0, 0.045, 0.090 and 0.36 equivalent ratio of Cr~ to inhibitor with significant deterioration at the l.Q equivalent ratio. Likewise, much poorer performance at the higher Cr 3 equivalent ratio was observed at 2 pp~ of inhibitor.
Table I
Effect of Cr~3 On Inhibition of Ba~04 Py Belsperse 161 ppm Equivalent visual observation inhibitor Cr/inhibitor Pa~04 inhibition ~ 4 4 0.045 4 0.090 4 0.36 2 4 1.0 4 2 0.045 2 2 0.090 2 2 0.36 2 3 2 1.0 ~ -Le~end for visual observation:
rankin~s from 4 to 1 in order of increasing cleanliness.
4 - heavy precipitation.
IN SUBTERRANFAN FO~TIONS
This invention relates to inhibitin~ scale formation in a well penetratin~ a subterranean formation and particularly a method for increasin~ retention of the scale inhibitor in the formation.
In the production of water7 oil and ~as from subterranean S formations, scale deposits can frequently result in: plug~ed well bores, plu~ed well casin~ perforations, plu~ed tubin~ strin~s, stuck downhole safety valves as well as other valves, stuck downhole pumps and other downhole and surface equipment and lines, scaled formations and fractures in the vicinity of the well. ~uch scale lo formation can occur as a result of mixin~ of incompatible waters in the well, i.e., waters which when mixed ~roduce precipitates, or as a result of temperature and pressure chan~es and the like in the produced waters durina production. Cenerally, incompatible waters are formed as a consequence of waterfloodin~, as injected sea water mixes with formation water in the borehole durin~ water breakthrou~h. The more common concern is scales deposited because of chan~es in supersaturation or solubility of minerals in the formation or produced waters caused by pressure and temperature chan~es, or changes in other physical and chemical environments such as ~as compositions, ratio of gas/oil/water. Precipitation frequently encountered as scale include calcium carbonate, calcium sulfate, barium sulfate, ma~nesium carbonate, ma~nesium sulfate, and strontium sulfate. The deposition of scale is a very complex crystalline process initiated by a supersaturation-induced nucleation of a precipitate of the mineral, scale ions contact these nuclei and the crystal ~rows in a certain cr~stalline pattern. Ihe adherence of these mineral crystals unto the formation matrix, perforation, well-bore, tubin~s and equipment is a not well-understood process but once initiated, appears to be F-~1619 --2-~
spontaneous as seen by the increasin~ thickness of the scale deposit and the steady decline in productivity. In some cases, production can be halted when valves and pumps are stuck -- creatin~ a potentially dangerous situation. The normal practice of treatin~
with inhibitors does protect scales from formin~ in the perforations or near well-bore areas, well tubulars, downhole pump, other downhole equipment9 and surface equipment. B~t such practice results in very short life requirin~ frequent re-treatments and necessitating periods of loss of pr~duction. A siqni~icant extension of life means that down-times due to re-treatments will be much less frequent translating to better economics of operation.
The squeezin~ of chemicals for protectin~ wells, particularly oil wells, is widely practiced. A "squeeze" ,ob mi~ht last one to six months depending on the nature of the subterranean formation into which the chemical is squeezed and the rate at which fluids e.g., oil and water, are produced by the well. A formation that has low permeability but hi~h porosity, and from which low rates of oil and water are produced would likely bleed injected chemicals back for a long time. However, a problem arises with hi~hly permeable formations which produce hi~h rates of oil and water. This type of formation retains chemicals for only a short time because they are readily washed out of the permeable zones of the formation by the hi~h volumes of produced fluids. The inhibitor is normally retained by an adsorption mechanism into the formation matrix and released by desorption durin~ fluids production. In ~eneral, at least a third or more of the inhibitor is not absorbed but is immediately produced back, resultin~ in ineffective use and frequent retreatments.
In an article by Carlber~ and Essel entitled, "Strontium S~1lfate Scale Control by Inhibitor Squeeze Treatment in the Fateh Field", published in the Journal of Petroleum Technolo~y, in June 19~2, there is disclosed a method for inhibitin~ scale formation in a subterranean limestone formation by injectin~ an acid form of a polyphosphonate which forms a sli~htly soluble calcium salt.
. .
~-4619 Calcium ions released on dissolution of some of the limestone (calcium carbonate) rock by the acid precipitates calcium polyphosphonate allowing ~reater retention in the rock. However, this method does not work in sandstones, because sandstones are not soluble in acids, nor do they form calcium ions even when dissolved.
U.S. Patent 3,827,977 to L.~l. Miles and G.F. Kin~, issued Aug. 6, ~97~, discloses a method of increasing retention of an inhibitor by in situ formation of the relatively water or brine insoluble polycation salt of polyacrylic acid or hydrolyzed polyacrylamide. A stron~ acid solution used initially inhibits reaction of the salts but the acid is eventually neutrallzed by the formation rock allowing the deposition of the water insoluble metal salt of the inhibitor in the formation. In the practice of the Miles et al invention, a larger than stoichiometric amount of the polyvalent metal salt (with Ca 2 and zn~2 preferred) associated with the carboxylic acids ~roups of the inhibitor is required to insure complete reaction of the inhibitor (i.e., equivalent ratio cf polyvalent metal cation to carboxyl;c acids ~reater than 1.0). For example, Miles et al cites a concentration of about 0.5 to 1.5%
solutions by weight Ca with 0.5 to 1% solutions of the sodium polyacrylate. Assumin~ a molecular wei~ht of 5000 for the polyacrylate (at 1% by weight) and Ca 2 at 0.5 %, the equivalent ratio of Ca to carboxylic acid ~roups is 1.8; while the mole ratio of Ca to polyacrylate is 62.5. The limiting factor in the use of such high concentrations of multivalent metal ions is the danger of dama~ing the formation by plugging it with premature precipitation.
In an article by KØ ~eyers et al, entitled "Control of Formation ~amage at Prudhoe Pay, AK, by Inhibitor Squeeze Treatment", published in the Journal of Pet. Tech., pp 26, in June 1985, they caution against the presence of high concentrations of calcium when the inhibitor is s~ueezed into a well for the same reason. The normal criteria for selection of an inhibitor includes having hi~h solubility in the reservoir brine and low susceptibility to precipitation by divalent cations. Therefore, introduction of the inhibitor in the manner tauaht by ~qiles et al affords little or no protection in inhibitin~ premature precipitation that causes plu~in~ of the formation.
According to the present invention the danger of dama~in~
the formation by precipitation is avoided by limitin~ the equivalent ratio of multivalent cations to inhibitor to a ratio of 0.5 or less and limitin~ inhibitor molecular wei~ht ran~e to 500 to 10,000 which extends the life of the polyacrylate inhibitor 2 to 5 times that of a similar treatment without the polyvalent cation. Furthermore, at these low polyvalent cation concentrations, the polyacrylic inhibitor is very active while the activity is dim nished si~nificantly at a high polyvalent cation concentration (equivalent ratio ~reater than 0.5)0 The present invention proYides for a method for inhibitin~
scale in a well penetrating a subterranean formation for the production of fluids from the formati~n comprising dissolvin~ a polymeric inhibitor comprising an alpha, beta-ethylenically unsaturated carboxylic acid havin~ a molecular wei~ht of 500 to 10,000 and a polyvalent cation in a aqueous solution having a p~ not greater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate inhibitor is less than or equal to 0.5 and injecting the polyacrylate inhibitor, polyvalent cation aqueous solution into the formation about the well and allowin~ natural conditions in the formations to raise the pl-l of -the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The polyvalent cation comprises any cation with a valence of two or greater, preferably Cr 3, Ti 3, Al 3, Fe 3 or Zr ~ in the form of a water-soluble salt. ~uitable polymeric inhibitors include all homopolymers or copolymers (composed of two or more co-monomers) containing as one of its components, an alpha beta-ethylenically unsaturated acid monomer such as acrylic acid, methacrylic acid, diacids such as maleic acid (or maleic anhydride), F-4619 ~~5 ~
itaconic acid, fumaric acid, mesaconic acid, citraconic acid and the like, monoesters of diacids with alkanols having 1-8. carbon atoms, and mixtures thereof. For simplicity, these acid monomers shall henceforth be called acrylic monomers. When the inhibitor is a copolymer, the other component monomers can be any alpha, beta-ethylenically unsaturated monomer with either a non-polar group such as styrene or olefinic monomers or a polar functional ~roups such as vinylacetate, vinyl chloride, vinyl alcohol, acrylate ester, vinylpyridine, vinyl pyrrolidone, acrylamide or acrylamide derivatives, etc., or with ionic functional ~roups such as styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (A~S), vinylsulfonic acid, vinylphosphonic acid. The polyacrylate inhibitor includes modification of the polymers described above such as phosphino-polyacrylic acid sold under the trade mark "B2lsperse 161" or "Belasol S-29" by Ciba Gei~y. The preferred polyacrylate inhibitor is phosphino-polyacrylic acid.
Fi~. 1 illustratcs the concentration (ppm) of inhibitor in produced water versus pore volume of back-produced water for a 2000 ppm inhibitor solution of'~elsperse 161"
Fig. 2 illustrates the concentration (ppm) of inhibitor in produced water versus pore volume of back-pro~lced water for a 2000 ppm inhibitor solution of'~elsperse 161"and 22 ppm Cr 3 (equivalent ratio = 0.045).
In accordance with the present invention, a subterranean formation is penetrated by a wellbore, includin~ a casin~ in f~uid communication therewith by means of well casing perforations in the zone of the formation. Production occurs from the formation by the flow of fluids includln~ oil, gas and water throu~h the perforations into the well bore with the fluids then being recovered. The production of fluids from the well can be inhibited by the formation of scale which plugs or partially plu~s perforations in the casing of the wellbore, tubin~ inside the casing, downhole equipment such as pumps and safety valves or the formation near the well.
~-4619 --6--In the present invention, a polyacrylate scale inhibitor havin~ a molecular wei~ht range from 500 to 10,000 and a polyvalent cation are dissolved in an acidic aqueous solution havin~ a pH not ~reater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate is equal to or less than 0.5. Suitable cations are any cations with a valence of 2 or ~reater, preferably Cr 3, Ti 3, A1~3, Fe 3 and Zr 4, in the form of a water-soluble salt.
Generally any stron~ acid or mixtures of stron~ and weak acids can be used to prepare the acidic aqueous solution. Sulfuric acid should not be used for this purpose because the sulfate ions present scale problems. Sui-table polyacrylate inhibitors include all homopolymers or copolymers (composed of two or more co-monomers) containin~ as one of its components, an alpha, beta-ethylenically unsaturated acid monomer such as acrylic acid, methacrylic acid, diacids such as maleic acid (or maleic anhydride), itaconic acid, fumaric acid, mesaconic acid, citraconic acid and the like, monoesters of diacids with alkanols havin~ carbon atoms, and mixtures thereof. For simplicity, these acid monomers shall henceforth be called acrylic monomers. When the inhibitor is a copolymer, the other component monomers can be any alpha, beta-ethylenically unsaturated monomer with either a non-polar ~roup such as styrene or olefinic monomers, or a polar functional ~roup such as vinylacetate, vinyl chloride, ~inyl alcohol, acrylate ester, vinyl pyridine, vinyl pyrrolidone, acrylamide or acrylamide derivatives, etc., or with ionic functional ~roup such as styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid (AMPS), vinylsulfonic acid, vinylphosphonic acid. The polyacrylate inhibitor includes modification of the polymers described above such as phosphino-polyacrylic acid sold under ~he trade mark "Belsperse 161" or "Belasol S-29" by Ciba Gei~y, The molecular wei~ht ran~e of the polyacrylate inhibitor utilized in this invention is from 500 to 10,000. ~s the inhibitor molecular wei~ht increases, there is ~reater suceptibility towards uncontrolled precipitation and dama~e to the formation and well-bore. The selection of the scale ~-~619 `~7~~
inhibitor is hiFhly dependent upon the characteristics of the formation, the composition, and other environmental factors. As acidic aqueous solution containin~ a polyacrylate inhibitor and a polycation is injected, the acid prevents any premature precipitation or insolubilization by allowing the polycation to form a water-soluble complex with the inhibitor. Upon enterin~ the formation the acid is dissipated and the natural conditions in the formation raises the pH of the solution an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex. The solution containin~ the complexed scale inhibitor is retained in the form~tion and slowly released from the formation ~ith the produced aqueous fluids as the well is produced thereby inhibitin~ formation of chan~in~ scale deposits in the formation in the vicinity of the wellbore, casin~ perforations, tubin~ and other downhole equipment as well as corrosion in the well. Generally, ir,jection of the aqueous acid solution of polyacrylate and polyvalent cation is desi~nated to extend at least several inches, 3 or 4, (7.5 to 10 cm) to several feet, 3 or 4, or more, (1 to 1.3~, or more) from the wellbore. In ~eneral, an amount of inhibitor solution is injected into the formation surroundin~ the oil well that is sufficient to feed back a concentration of the inhibitor effective to prevent the formation of scale deposits. The acidic aqueous solution of polyvalent cations and polyacrylate may be driven to ~reater radial distances by usinF a waterflood of water, oil or Fas to assure that the scale inhibitor will be exposed and retained to a much ~reater surface area in the producin~
formations. Typically, the effective concentration of inhibitor bein~ fed back is in the ran~e of 0.05 to 50 ppm and preferably 0.5 to 10 ppm in the produced water. The exact quantity of inhibitor solution used for a treatment is dependent on a number of factors unique to the well that is bein~ treated. These factors include:
the de~ree of supersaturation expected of the scale formin~ minerals in the produced water~ the rate of production of water, temperature and pressure profile in the well, the len~th of protection desired which is related to the radial distance reached by the inhibitor treatment, and others. The concentration of polyacrylate inhibitor employed in the acidic aqueous solution can vary from 0.1 to 20.0 percent by wei~ht in fresh water, sea water or other available brines, but preferably in the 0.5 to 5.0 percent by weight range.
After the scale inhibitor has been deposited into the formation, production of fluids including oil and ~ater from the well is resumed. The scale inhihitor is released slowly at lo effective concentration to inhibit scale formation or corrosion for a substantial period of time. The scale treatment of this invention may be repeated on a regular basis based on experience or when the che~ical return concentration falls below minimum requirements or when other scale formin~ indicators indicate that additional treatment should be applied.
Phosphino-polyacrylic acid with an average molecular wei~ht of 1000 to 1200 sold under the trademark "~elsperse 161" or "Belasol ~-Z9" by Ciba Geigy is a very versatile inhibitor for treatmeot of sulfate and carbonate scales. '~elsperse 161"is used here as a ~odel inhibitor to demonstrate the concept. Cr 3 (from CrC13~ 6 H2O) is used as an example of a polyvalent cation.
Example 1 The effect of Cr 3 concentration on the inhibition of barium sulfate by'~elsperse 161"was investi~ated. In each case, 2 cc of a simulated sea water containing Cr 3 and the inhibitor was mixed with 8 cc of a simulated connate water (or formation water;
water native to the reservoir) and observed visually for precipitation of bariu~ sulfate after standing for 20 hours at 24C. The results shown in Table 1 indicate excellent inhibition at 4 ppm of'~elsperse 161"with 0, 0.045, 0.090 and 0.36 equivalent ratio of Cr~ to inhibitor with significant deterioration at the l.Q equivalent ratio. Likewise, much poorer performance at the higher Cr 3 equivalent ratio was observed at 2 pp~ of inhibitor.
Table I
Effect of Cr~3 On Inhibition of Ba~04 Py Belsperse 161 ppm Equivalent visual observation inhibitor Cr/inhibitor Pa~04 inhibition ~ 4 4 0.045 4 0.090 4 0.36 2 4 1.0 4 2 0.045 2 2 0.090 2 2 0.36 2 3 2 1.0 ~ -Le~end for visual observation:
rankin~s from 4 to 1 in order of increasing cleanliness.
4 - heavy precipitation.
3 = moderate precipitation.
2 = sli~ht precipitation.
1 = clear, no precipitation.
Examrle 2 This example illustrates the beneficial extension of life of a polyacrylate inhibitor treatment provided by low concentrations of polyvalent cation. Berea sandstone cores havin~ 1" (2.5 cm) diameter by 3" (7.5 cm) len~th and brine permeability of 148 to 277 millidarcy (md) were vacuum evacuated in a Hassler cell overni~ht before its pore volume was determined. After some ~reliminary saturation with brine, the core was heated to 90C and flooded with a 2000 ppm solution of Belsperse 161 inhibitor solution in simulated sea water (composition described in Table 2) at pH 2.5 for about 40-50 pore volumes (PV) to ensure saturation covera~e. The core was then back produced with 70 to 120 PV of simulated connate water (composition described in Table 2) at pH 5.7 and at 90C to mimic an on~oin~ waterflood. The concentration of the inhibitor was followed with the method described in my Canadian patent applica-tion No. 586,127, filed December 16, 1988. As shown in Figure 1, the inhibitor is exhausted after only 2~ PV of ?~
~n. . ~
connate water has been back produced. In contrast, as shown in ~igure 2, when 22 ppm Cr 3 was incorporated with the 2000 ppm of Belsperse 161 floodin~ solution and the same coreflood experiment carried ou~, 5 ppm of the inhibitor was still produced after 113 PV. This represents an extension of inhibitor life of almost 5 times at a Cr 3 to inhibitor equivalent ratio of only 0.045.
Another advanta~e associated with the use of low Cr 3 mole ratio was the negligibly small change in pressure measured during the inhibitor saturation phase and the back production phase. This suggests that formation damage is unlikely to be encountered.
Additional cross-linking treatment allowed useful concentrations of from 3 to 5 ppm of Pelsperse 161 to be released after back production of 93 to 113 PV of simulated connate water as shown in Table 3. For core run ~5, excellent results were also obtained for a coreflood study at 0.36 equivalent ratio of Cr 3 to Pelsperse 161, which is still much below the stoichiometric equivalent ratio of 1Ø
Table 2 Simulated brine compositions ,"~
~u grams per liter components sea waterconnate water MgC12 6 H20 11.7 0.77 CaC12 2 H2O 1.47 2.00 ~Cl 0.70 0.66 PaC12 2 H20 0.24 SrC12 6 H20 0.53 NaS04 3.92 NaCI 25.10 49.l9 de-ionized ll2O to 1 liter Table 3 Extension of Life of ~elsperse 161 at Low Cr~3 _ evels core Equivalent ratio m~/L
run Cr/Belsperse 161 PV Belsperse 161 0 2q 0 2 0.045 113 5 3 0.045 112 3.3 4 0.045 93 2.6 0.36 120 3 2000 p~m ~elsperse 161 was used For the initial flooding. For cores 2-4, 22 ppm Cr 3 was also present. In core 5, 176 ppm of Cr 3 was present.
Example 3 This example demonstrates that the benefits derived from multivalent cation cross-linkin~ of a polyacrylate inhibitor using low to medium permeability Berea sandstone cores (Example 2) can be extended to hi~her permeability cores. The same experiments shown in Example 2 were conducted using Perea cores havina a brine permeability in the range of 350 to 650 md. ~!ithout Cr 3, the Pelsperse 161 inhibitor is depleted at about 25 PV, while at a 0.045 equivalent ratio of Cr to inhibitor, 3 ppm of the inhibitor is still produced after 68 PV a~ shown in Table 4. A nearly 3-fold extension in life was achieved with Cr 3 cross-linking. It should be noted that in all the Cr 3 containin~ r~ms, there was potential for higher extensions of inhibitor life, since the experiment was arbitrarily terminated at the specified PV.
Table 4 Fxtension of Life of Belsperse 161 at Low Cr~3 LeYels With Berea Sandstone Cores of Brine Permeability of 350-650 md core Equivalent ~atio mg/L
run Cr/~elsperse 161 W Pelsperse 161 -7 0.045 68 3 2000 ppm Belsperse ]61 wi-th or without 22 ppm Cr 3 was used for the initial flooding.
2 = sli~ht precipitation.
1 = clear, no precipitation.
Examrle 2 This example illustrates the beneficial extension of life of a polyacrylate inhibitor treatment provided by low concentrations of polyvalent cation. Berea sandstone cores havin~ 1" (2.5 cm) diameter by 3" (7.5 cm) len~th and brine permeability of 148 to 277 millidarcy (md) were vacuum evacuated in a Hassler cell overni~ht before its pore volume was determined. After some ~reliminary saturation with brine, the core was heated to 90C and flooded with a 2000 ppm solution of Belsperse 161 inhibitor solution in simulated sea water (composition described in Table 2) at pH 2.5 for about 40-50 pore volumes (PV) to ensure saturation covera~e. The core was then back produced with 70 to 120 PV of simulated connate water (composition described in Table 2) at pH 5.7 and at 90C to mimic an on~oin~ waterflood. The concentration of the inhibitor was followed with the method described in my Canadian patent applica-tion No. 586,127, filed December 16, 1988. As shown in Figure 1, the inhibitor is exhausted after only 2~ PV of ?~
~n. . ~
connate water has been back produced. In contrast, as shown in ~igure 2, when 22 ppm Cr 3 was incorporated with the 2000 ppm of Belsperse 161 floodin~ solution and the same coreflood experiment carried ou~, 5 ppm of the inhibitor was still produced after 113 PV. This represents an extension of inhibitor life of almost 5 times at a Cr 3 to inhibitor equivalent ratio of only 0.045.
Another advanta~e associated with the use of low Cr 3 mole ratio was the negligibly small change in pressure measured during the inhibitor saturation phase and the back production phase. This suggests that formation damage is unlikely to be encountered.
Additional cross-linking treatment allowed useful concentrations of from 3 to 5 ppm of Pelsperse 161 to be released after back production of 93 to 113 PV of simulated connate water as shown in Table 3. For core run ~5, excellent results were also obtained for a coreflood study at 0.36 equivalent ratio of Cr 3 to Pelsperse 161, which is still much below the stoichiometric equivalent ratio of 1Ø
Table 2 Simulated brine compositions ,"~
~u grams per liter components sea waterconnate water MgC12 6 H20 11.7 0.77 CaC12 2 H2O 1.47 2.00 ~Cl 0.70 0.66 PaC12 2 H20 0.24 SrC12 6 H20 0.53 NaS04 3.92 NaCI 25.10 49.l9 de-ionized ll2O to 1 liter Table 3 Extension of Life of ~elsperse 161 at Low Cr~3 _ evels core Equivalent ratio m~/L
run Cr/Belsperse 161 PV Belsperse 161 0 2q 0 2 0.045 113 5 3 0.045 112 3.3 4 0.045 93 2.6 0.36 120 3 2000 p~m ~elsperse 161 was used For the initial flooding. For cores 2-4, 22 ppm Cr 3 was also present. In core 5, 176 ppm of Cr 3 was present.
Example 3 This example demonstrates that the benefits derived from multivalent cation cross-linkin~ of a polyacrylate inhibitor using low to medium permeability Berea sandstone cores (Example 2) can be extended to hi~her permeability cores. The same experiments shown in Example 2 were conducted using Perea cores havina a brine permeability in the range of 350 to 650 md. ~!ithout Cr 3, the Pelsperse 161 inhibitor is depleted at about 25 PV, while at a 0.045 equivalent ratio of Cr to inhibitor, 3 ppm of the inhibitor is still produced after 68 PV a~ shown in Table 4. A nearly 3-fold extension in life was achieved with Cr 3 cross-linking. It should be noted that in all the Cr 3 containin~ r~ms, there was potential for higher extensions of inhibitor life, since the experiment was arbitrarily terminated at the specified PV.
Table 4 Fxtension of Life of Belsperse 161 at Low Cr~3 LeYels With Berea Sandstone Cores of Brine Permeability of 350-650 md core Equivalent ~atio mg/L
run Cr/~elsperse 161 W Pelsperse 161 -7 0.045 68 3 2000 ppm Belsperse ]61 wi-th or without 22 ppm Cr 3 was used for the initial flooding.
Claims (6)
1. A method for inhibiting scale in a well penetrating a subterranean formation for the production of fluids from the formation comprising:
(a) dissolving a polymeric inhibitor comprising an alpha, beta-ethylenically unsaturated carboxylic acid having a molecular weight range of 500 to 1,000 and a polyvalent cation in an aqueous solution having a pH not greater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate inhibitor is less than or equal to 0.5 in said aqueous solution; and (b) injecting said inhibitor, polyvalent cation aqueous solution into the formation about the well and allowing natural conditions in the formation to raise the pH of the solution in an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex.
(a) dissolving a polymeric inhibitor comprising an alpha, beta-ethylenically unsaturated carboxylic acid having a molecular weight range of 500 to 1,000 and a polyvalent cation in an aqueous solution having a pH not greater than 3 wherein the equivalent ratio of polyvalent cation to polyacrylate inhibitor is less than or equal to 0.5 in said aqueous solution; and (b) injecting said inhibitor, polyvalent cation aqueous solution into the formation about the well and allowing natural conditions in the formation to raise the pH of the solution in an amount sufficient to cause controlled precipitation and increased deposition of the scale inhibitor in situ in the form of the polyvalent cation-polyacrylate complex.
2. The method of claim 1 wherein the polyvalent cation is Cr+3, Ti+3, Al+3, Fe+3 or Zr+4 in the form of a water-soluble salt.
3. The method of claim 1 wherein the polymeric inibitor is selected from polyacrylic acid, phosphino-polyacrylic acid, copolymers of acrylic acid and 2-acrylamido-2-methylpropanesulfonic acid and copolymers of methacrylic acid and acrylic acid.
4. The method of claim 1 wherein the polymeric inhibitor is a homopolymer selected from polyacrylic acid, polymethyacrylic acid, polyitaconic acid and polymaleic acid.
5. The method of claim 1 wherein the polymeric inhibitor comprises an alpha, beta-ethylenically unsaturated carboxylic acid monomer copolymerized with a monomer selected from an alpha, beta-ethylenically unsaturated monomer containing a non-polar group comprising styrene and olefinic monomers, an alpha, beta-ethylenically unsaturated monomer containing a polar functional group selected from vinylacetate, vinyl chloride, vinyl alcohol, acrylate ester, vinyl pyridine, vinyl pyrrolidone, acrylamide and acrylamide derivatives and an alpha, beta-ethylenically unsaturated monomer containing an ionic functional group selected from styrenesulfonic acid, 2-acrylamido-2-methylpropanesulfonic acid, vinylsulfonic acid and vinylphosphonic acid.
6. The method of claim 5 wherein the alpha, beta-ethylenically unsaturated carboxylic acid monomer is selected from acrylic acid, methacrylic acid, maleic acid, maleic anhydride, itaconic acid, fumaric acid, mesaconic acid and citraconic acid.
4409h/0403h
4409h/0403h
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US13049287A | 1987-12-09 | 1987-12-09 | |
| US130,492 | 1987-12-09 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA1295119C true CA1295119C (en) | 1992-02-04 |
Family
ID=22444948
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA000585305A Expired - Lifetime CA1295119C (en) | 1987-12-09 | 1988-12-08 | Method of increasing retention of scale inhibitor in subterranean formations |
Country Status (4)
| Country | Link |
|---|---|
| CA (1) | CA1295119C (en) |
| DE (1) | DE3841030C2 (en) |
| GB (1) | GB2213516B (en) |
| NO (1) | NO177764C (en) |
Families Citing this family (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| AU653518B2 (en) * | 1990-05-31 | 1994-10-06 | Mobil Oil Corporation | Inhibition of scale formation from oil well brines utilising a slow release composition |
Family Cites Families (2)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| GB1290554A (en) * | 1969-11-06 | 1972-09-27 | ||
| US3827977A (en) * | 1969-11-25 | 1974-08-06 | Atlantic Richfield Co | Composition for inhibiting scale formation in oil well brines |
-
1988
- 1988-12-06 DE DE19883841030 patent/DE3841030C2/en not_active Expired - Fee Related
- 1988-12-07 NO NO885437A patent/NO177764C/en unknown
- 1988-12-08 GB GB8828734A patent/GB2213516B/en not_active Expired - Lifetime
- 1988-12-08 CA CA000585305A patent/CA1295119C/en not_active Expired - Lifetime
Also Published As
| Publication number | Publication date |
|---|---|
| GB8828734D0 (en) | 1989-01-11 |
| GB2213516A (en) | 1989-08-16 |
| DE3841030A1 (en) | 1989-06-22 |
| NO885437L (en) | 1989-06-12 |
| NO177764C (en) | 1995-11-15 |
| DE3841030C2 (en) | 2000-08-17 |
| NO177764B (en) | 1995-08-07 |
| GB2213516B (en) | 1991-10-16 |
| NO885437D0 (en) | 1988-12-07 |
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