NZ209694A - Scale formation control treatment in steam generation feedwater - Google Patents

Description

New Zealand Paient Spedficaiion for Paient Number £09694 II HAKIMS 209694 N.Z. fATENT OFFICE 27SEP1904 4 RECEIVED N.Z.No.

NEW ZEALAND Patents Act 1953 COMPLETE SPECIFICATION "TREATMENT OF STEAM GENERATION FEEDWATER" We, UNION OIL COMPANY OF CALIFORNIA, incorporated under the laws of the State of California, of 461 South Boylston Street, Los Angeles, California 90017, United States of America, do hereby declare the invention, for which we pray that a Patent may be granted to us, and the method by which it is to be performed, to be particularly described in and by the following statement : - Priority Date(s): Complete Specification Filed: Class: ^/f$//&,• mm! JkH Publication Date: P ... P.O. Journal, No: ../.£SP (followed by 1A) f 2 0 9 6 9 4 -iA- TREATMENT OF STEAM GENERATION FEEDWATER D BACKGROUND OF THE INVENTION Field of the Invention This invention relates to a method for treating a 5 liquid water-containing fluid stream being transported through a conduit in which at least a portion of the liquid water flashes to steam during transit. More particularly, the invention relates to such a method wherein the hot liquid water-containing fluid stream tends to build up a 10 scale and/or corrode the surfaces of the conduit with which it comes in contact. By use of the method of this invention, the build-up of scale is inhibited and/or any scale already formed is at least partially removed, and corrosion is mitigated.

Description of the Prior Art Many industrial operations involve passing a hot water-containing fluid stream through a conduit under conditions, such as a lowering of the pressure, at which at least a portion of the hot water flashes to steam. If 20 the hot water is a brine containing appreciable amounts of dissolved salts, this flashing is often accompanied by the formation of scale on the surfaces of the conduit contacted by the hot water-containing fluid stream. This deposition of scale tends to build up over a period of time 25 and restrict further fluid flow through the conduit. This necessitates either operation at a reduced flow rate or an increase in the amount of power used to move the fluid through the conduit. In extreme cases, the conduit can become completely plugged with scale, and the industrial 30 operation must be shut down for maintenance. An example 209694 of such an industrial operation involves the generation of steam which can be used as a source of heat or to generate power. Various methods of generating steam utilize fossil-fuel steam generators, nuclear steam 5 supply systems and geothermal steam generator units.

Various proposals have been made to decrease the scale formation and/or corrosion in steam generating equipment. These methods include the addition to the feedwater of such materials as sodium phosphate to 10 precipitate calcium ions and other hardness constituents present, sodium hydroxide to raise the pH of the system, a complex metal-chelating compound such as ethylenediamine tetracetic acid or nitrilotriacetic acid to complex the hardness constituents, and a 15 neutralizing or filming compound such as ammonia, morpholine, cyclohexylamine, hydrazine, or octadecylamine acetate to produce an alkaline gas in the steam and react with the acidic gases produced frcaa the feedwater.

The report "On-Line Tests of Organic Additives for the Inhibition of the Precipitation of Silica from Hypersaline Geothermal Brine II. Tests of Nitrogen-Containing Compounds, Silanes, and Additional Ethoxylated Compounds", J.E. Harrar, F.E. Locke, 25 C.H. Otto, Jr., L.E. Lorensen and W.P. Frey, Lawrence Livermore Laboratory, prepared for U.S. Department of Energy under Contract No. W-7405-Eng-48, June 1, 1979, describes several classes of organic compounds which were screened as potential geothermal scale control 30 agents. The leading antiscalant candidate was Ethoguad 18/25, methylpolyoxyethylene (15) octadecylammonium chloride. Similar quaternary ammonium compounds tested included dimethyl benzyl, coco, tallow and trimethyl ammonium chloride derivatives. 2096 9 -v '*) 30 While each of the aforementioned treatments has met with some success in particular applications, the need exists for a further improved well treating process to reduce scale deposition and corrosion of metal equipment during the production and subsequent handling of well fluids containing hot brine, especially geothermal fluids.

Accordingly, it is a principal object of this invention to provide a method for inhibiting the deposition of scale onto and the corrosion of fluid-handling equipment contacted by a hot water-containing fluid stream and for removing such scale from such surfaces.

It is a further object of this invention to provide such a method wherein the hot water-containing fluid stream is a steam generating fluid stream.

It is a still further object of this invention to provide such a method wherein the steam generating fluid is a geothermal fluid.

It is a still further object of -this invention to provide such a method wherein the geothermal fluid comprises principally an aqueous brine.

It is another object of this invention to provide such a method wherein a treating material is admixed with the feedwater prior to the generation of the major portion of the steam.

It is yet another object of this invention to provide such a method wherein the treating material is bled into a geothermal fluid at or near the producing interval of a well as the geothermal fluid is produced from a reservoir.

It is yet another object of this invention to provide such a method wherein the treating material is injected into the formation penetrated by a geothermal well. 209694 Other objects, advantages tion will be apparent from the and appended claims. and features of the inven-following description SUMMARY OF THE INVENTION * Briefly, the invention provides a method for treating a hot liquid^ water.rrcontaining fluid stream passing through a reservoir or a conduit, which water contains dissolved salts, in which reservoir or conduit at least a portion of the liquid water flashes to steam, to inhibit the formation of scale from the dissolved salts deposited on the reservoir or conduit and/or dissolve any such scale previously formed and to inhibit corrosion of the conduit wherein there is added to the hot liquid water-containing fluid stream prior to the flashing a treating solution of a water-soluble compound which provides a nitrogen-containing cation capable of flashing to become a gas at high temperatures sleeted from the group consisting of ammonium halides, ammonium salts of inorganic acids, ammonium salts of organic acids, ammonium salts of alpha hydroxy organic acids, quaternary ammonium salts of inorganic acids, quaternary ammonium salts of organic acids, amine hydrochlorides, amine salts of inorganic acids, amine salts of organic acids, and amides. Optionally, the added solution also contains a water-soluble or dispersible polymer. Also the treating solution can optionally contain an effective amount of a buffering agent which is especially useful when the treating solution is used to remove scale already formed in a reservoir or a conduit. 209694 DETAILED DESCRIPTION OF THE INVENTION In many industrial operations, a fluid stream containing liquid hot water, which water contains dissolved solids, is passed through a conduit. Depending on the temperature and pressure conditions of the fluid stream, it can be composed entirely of a liquid hot water or a mixture of such water and steam. For example, geothermal fluids in subterranean reservoirs typically are at a temperature of about 400° to 700° F. and a pressure of about 400 to "700 psig. When the geothermal fluid moves through the reservoir to a well and ascends through the well to the surface, the temperature of the fluid stream can drop as much as 100°F or more, and the pressure is also substantially reduced. When the geothermal fluid is utilized, for example as a source of heat or to generate power, it is passed through various conduits. For example, the conduits through which a hot geothermal fluid produced from a well passes during its utilization to generate power in a power plant include one or more wellhead separators in which the major portion of the produced gas phase of the geothermal fluid is separated from the liquid phase, a flash vessel wherein the pressure on the hot liquid phase is reduced to cause a portion of the liquid to flash to steam, a steam turbine/generator which produces the power, a pump for reinjection of the spent brine back into a subterranean reservoir and the various conduits connecting these units.

During such utilization the temperature of the fluid stream can drop as much as an additional 100° F. or more, and the pressure is also further reduced. The hot pressurized spent geothermal fluid is then ready for disposal, such as by reinjection into a subterranean reservoir. Sometimes, prior to reinjection, the spent 209694 geothermal fluid is blended with a cold brine from another source and condensate from the power plant which also must be disposed of. During such blending of the fluid to be reinjected, the temperature can drop further to 5 about 185° F or lower. a When a change in conditions occurs, e.g., a reduction in pressure or an increase in temperature, during the passage of a hot liquid water-containing stream through a conduit, a portion of the water phase can flash to 10 steam. When the liquid phase also contains dissolved solids, the solids may decompose to form anions with at least a portion of the decomposition products flashing into the vapor phase. For example, if the water phase contains dissolved bicarbonate ions, the bicarbonate 15 ion decomposes as follows: HC03~ > C02 + 0H~ The carbon dioxide partitions into the gas phase while the hydroxyl ions remain in the liquid phase. The carbon dioxide can cause corrosion of any metal conduit with 20 which it comes in contact and/or combine with alkaline earth metal cations also present in the fluid stream to form a scale which adheres to the surfaces of the pores in the reservoir, the wellbore and other conduits and builds up in thickness over a period of tine. Carbon 25 dioxide is believed to cause corrosion by combining with water present in the system to form carbonic acid, a known corrosive. It is believed that scale formation is increased by the increase in alkalinity when carbon dioxide flashes. Similarly, silica can flash and form 30 silicate scales. As the fluid flow continues, the corrosion can cause failure of the conduit and/or the scale build-up can continue until the pore throats in the reservoir, the wellbore and other conduits become so plugged with scale that continued flow of fluids through 209694 . -7- the conduits is impaired. Often additional energy is required to maintain the desired rate of flow of fluids through the system. In some instances a substantially complete plugging of the conduits occurs, necessitating 5 a costly cessation of further operations for expensive ^ maintenance and repair. -jtQ/r One operation in which such hot liquid water-contain-ing stream is passed through a conduit is in the generation of steam. In most non-geothermal steam generation systems, 10 the boiler feedwater used is relatively pure. However, since the steam withdrawn is of even higher purity, contaminants entering with the boiler feedwater, even in small concentrations, accumulate in the boiler water. These contaminants, if not removed or treated, can 15 interfere with steam-water separation, or form deposits on the interior surfaces of the heat-absorbing components of the fluid-handling system. Such deposits increase metal temperatures and result in eventual failure of the pressure parts due to overheating.

Geothermal wells and steam collecting facilities present even more severe scale deposition and corrosion difficulties. One source of recoverable natural energy is geothermal energy stored in hot subterranean reservoirs. One way of utilizing this geothermal energy involves 25 drilling one or more wells into the reservoir, which may contain either a geothermal fluid or hot dry rocks. If it contains a geothermal fluid, i.e., steam brine, or a mixture of steam and brine, the fluid may be produced via a well. If it contains only hot dry rocks, 30 a relatively low temperature heat exchange fluid, generally water, is passed through the reservoir and recovered via a well after it has been heated by the rocks. In either instance, the process involves, in part, the production of geothermal fluid from a reservoir 35 to the surface via a well, subsequent handling of the 209694 fluid to utilize the geothermal energy, and usually, reinjection of the fluid back into the same or a different reservoir. Such utilization may involve generation of electric power by a turbine driven by geothermal 5 energy, passing the fluid through a helical rotary screw expander power system, using geothermal fluid in a binary power cycle with a working fluid such as isobutane in a regenerative heat exchanger, or direct utilization for its heat, water, or minerals content, for space 10 heating or process heating.

Within the reservoir the geothermal fluid exists at a high temperature and pressure. Under such conditions this aqueous fluid characteristically contains considerable amounts of various anions and cations dissolved from the reservoir rock, for example, sodium, potassium, calcium, magnesium, barium and iron cations and chloride, carbonate, bicarbonate, silicate, sulfate and sulfide anions. Among the more troublesome scales are the alkaline earth metal carbonates, such as calcium carbonate, and 20 silicate scales. Silicate scales are often complex and contain a number of cations. In many instances the scale is a mixture of two or more chemical compounds. For example, calcium carbonate can deposit in a mixture with a silicate scale. Deep, hot oil and/or gas producing 25 wells also can produce brine which contains similar scale-forming components.

As the geothermal fluid is produced from the reservoir via a well, utilized, and reinjected, certain changes take place. These changes include lowering of both the temperature and pressure of the fluid, flashing of at least a portion of the liquid component of the fluid and possibly mixing of two or more geothermal fluids of different composition coming from different 2 096 9 4 strata of the reservoir. As a result of these and other changes, salts precipitate and tend to adhere as hard deposits onto the surfaces of the pores in the reservoir and/or onto the metal surfaces in the well and surface 5 conduits with which they come in contact, e.g., the downhole and surface fluid-handling equipment, including _j\, flow lines, pumps, valves, rods, heat exchangers, and the like. While the exact composition of these precipitates varies widely and can include combinations of 10 any of the above-mentioned anions and cations, carbonate-containing scales have been found to be especially troublesome. As carbon dioxide, hydrogen sulfide and other gases flash, they contact and tend to corrode the metal in the system. Corrosion can even accelerate 15 buildup of scale deposits because the resulting corroded rough metal surfaces offer convenient sites to which scale crystals can adhere. A build-up of scale can sometimes concentrate and localize corrosive attack.

Scale formation is also undesirable because it cuts 20 down the heat transfer which can otherwise be achieved and can reduce the flow capacity of the system due to at least partial plugging of the flow passages by the scale. It has been found that the above-described corrosion and/or scale formation problems can be alleviated 25 by introducing into the water-containing fluid stream, at a point before a substantial amount of flashing has occurred, an effective amount of a treating fluid comprising a solution of a water-soluble ammonium salt, quaternary ammonium salt, amine salt or amide. Optionally 30 the treating fluid also contains a buffering agent. J - Preferably the solution also contains a water-soluble or dispersible polymer. The treating fluid can be mixad into the hot water-containing fluid stream downhole in the production well at a point near the producing 209694 strata as though a coiled tubing string anchored near the bottom of the well. Alternatively, a large volume of a dilute treating fluid can be prepared at the surface and injected down the well and into the reservoir. After 5 the treating fluid has been heated to near reservoir temperature, it is produced back out of the reservoir, into the well, and to the surface. The treating fluid can also be mixed into the hot water-containing fluid stream at various points in the surface faciliities, 10 as being introduced into conduits leading to a wellhead separator, the flash vessel, the turbine/generator and/or the reinjection pump.

While the mechanism by which the treating fluid functions in controlling scale formation and/or corrosion 15 is not completely understood, it is believed that in flashing, the compound, which provides a nitrogen-containing cation, decomposes as follows, using ammonium chloride as an example: NH4C1 £ NH3 + H CI The ammonia partitions into the gas phase while the hydrogen chloride remains in the liquid phase. These cations appear to flash at about the same time as the previously-described scale-forming anions. It is believed that the acid, e.g., hydrochloric acid remaining in 25 the liquid phase after decomposition of the nitrogen-containing cation, e.g., ammonium ion, neutralizes the alkaline anion, e.g. hydroxy ion, remaining in the liquid phase after decomposition of the scale-forming anion, e.g. bicarbonate ion, and is buffered in the liquid 30 phase. Thus, it is believed that the buffered decrease in the alkalinity of the aqueous phase inhibits scale formation and also corrosion.

The amount of treating agents required will vary with the particular treating agent employed as well as 209694 -ii- the nature of the salts dissolved in the liquid water portion of the fluid sream and/or the composition of the scale formed. Typically, an aqueous solution containing about 0.5 to 10 pounds per gallon of the compound which produces a nitrogen-containing cation will be used as a treating fluid. In general it has been found that about 2 to 50, preferably 5 to 10 milliequivalents of the nitrogen-containing cations per liter of the fluid stream have been effective in inhibiting and/or removing 5 to 10 milliequivalents of scale, respectively. When a polymer is included in the treating fluid, an effective amount of the polymer is about 5-100 parts per million by weight of the total fluid stream. An effective amount of a buffering agent, e.g., bicarbonate ion, is normally contained in the fluid stream. However, when a large volume of the treating fluid is not added to the fluid stream but is used independently of the fluid stream to remove 5 to 10 milliequivalents of the scale already formed, 0.2 to 0.4 milliequivalents of a buffering agent and an additional 0.3 to 0.5 milliequivalents of the nitrogen-containing cation are added per liter of the treating fluid prepared with 5 to 10 milliequivalents of cation per liter, respectively.

The water-soluble compound which provides a nitrogen-containing cation capable of flashing to become a gas at high temperatures suitable for use in this invention is selected from the group consisting of ammonium halides, ammonium salts of inorganic acids, ammonium salts of organic acids, quaternary ammonium halides, quaternary ammonium salts of inorganic acids, quaternary ammonium salts of organic acids, amine hydrochlorides, amine salts of inorganic acids, amine salts of organic acids, and amides.

Examples of suitable ammonium halides include ammonium chloride, ammonium bromide, ammonium fluoride, ammonium bifluoride and ammonium iodide. Particularly good results have been obtained with ammonium chloride. 209694 Examples of suitable ammonium salts of an inorganic acid include ammonium nitrate, ammonium nitrite, ammonium sulfate, ammonium sulfite, ammonium sulfamate, ammonium carbonate, ammonium borate, ammonium chromate, and ammonium 5 dichromate. Ammonium nitrate is preferred.

Examples of suitable ammonium salts of an inorganic acid include ammonium salts of mono-, di-, and tri-chloracetic acids, ammonium formate, ammonium acetate, ammonium citrate, ammonium tartrate, ammonium gallate, ammonium glyoxylate, 10 and ammonium benzoate.

Examples of ammonium salts of alpha hydroxy organic acids include ammonium glycolate and ammonium lactate.

The quaternary ammonium halides for use in this invention can be represented by the general formula: 15 R -RX R wherein at least one of the R groups is an organic hydrophobic group having 1 to 20 carbon atoms. The 20 other substituents are independently alkyl or hydroxyalkyl groups having 1 to 4 carbon atoms, benzyl groups or alkoxy groups of the formula (C2H40)nH or (CH^H^O)nH where n is 2 to 10. The preferred anion in the quaternary anion of the quaternary ammonium compound 25 is chloride. This can be replaced by various other anions, such as bromide, iodide, or ethylsulfate ions. Exemplary of suitable quaternary ammonium compounds y are tetramethyl ammonium chloride, dioctyl dimeth/1 ammonium chloride, dodecyl trimethyl ammonium chloride, cetyl 30 trimethyl ammonium chloride, cetyl trimethyl aaMonium bromide, dodecyl trimethyl benzyl ammonium chloride, ethyltrimethyl ammonium iodide, iodomethyltrimethyl 209694 ammonium iodide, tetraethyl ammonium ennea-iodide, tetraethyl ammonium hepta-iodide and methyl pyrridinium chloride. Particularly good results have been obtained with tetramethyl ammonium chloride.

Quaternary ammonium salts of inorganic acids for use in this invention include compounds similar to those having the above formula, only the anion is an inorganic acid rather than a chloride. Exemplary of suitable compounds are tetramethyl ammonium nitrate, dioctyl demethyl ammonium nitrite, dodecyl trimethyl ammonium sulfate, and similar compounds containing the sulfite, sulfonate, carbonate, borate, chromate and dichromate anions.

Quaternary ammonium salts of organic acids for use in this invention include compounds similar to those having the above formula, only the anion is an organic acid rather than a chloride. Exemplary of suitable compounds are tetramethyl ammonium formate, dioctyl dimethyl ammonium acetate, dodecyl trimethyl ammonium citrate, and similar compounds containing the tartrate, gallate, glyoxylate, and benzoate anions.

Also useful are amine hydrochlorides such as the mono-, di-, and tri-alkyl amine hydrochlorides, wherein the alkyl group contains 1 to 20 carbon atoms, straight chain or branched, aryl amine hycrochlorides, hydroxysub-stituted amine hydrochlorides and heterocyclic-substituted amine hydrochlorides. Examples of suitable materials include methylamine hydrochloride, ethylamine hydrochloride, propylamine hydrochloride, butylamine hydrochloride, dodecylamine hydrochloride, eicosylamine hydrochloride, diethylamine hydrochloride, triethylamine hydrochloride, benzylamine hydrochloride, naphthylamine hydrochloride, hydroxylamine hydrochloride, 2-aminopyridine hydrochloride and 4-aminopyridine hydrochloride. Parti- 2096 9 4-- cularly good results have been obtained with butylamine hydrochloride.

Amine salts of inorganic acids which can be used include ethylamine hydronitrate, butylamine nitrite, dimethylamine sulfate, dodecylamine sulfite, and similar amine salts of sulfamate, carbonate, borate, chromate, and dichromate anions.

Suitable amine salts of organic acids which can be used include methylaroine formate, diethylamine acetate, triethyl amine citrate, butylamine tartrate, and similar amine salts of gallate, glycoxylate, benzoate, and mono-, di-, and tri-chloroacetic acid anions.

Suitable amides include tertiary earboxylic acid alkylated amides characterized by the formula: wherein (1) R is hydrogen or an alkyl group containing 1 to about 8 carbon atoms, and (2) and R^ are the same or different alkyl groups containing 1 to about 8 carbon atoms.

Preferred alkylated amides are N,N-dimethylforaamide, N,N-diethylformamide, N,N-dimethylacetamide, N,N-diethyla-cetamide, N-N-dipropylacetamide, N, N-dimethylpropionamide. Other alkylated amides which may be used include N-methyl, N-methylacetamide, N-methyl, N-octylpropionamide, N-methyl, N-hexyl n-butyramide, N-methyl, N-propylcaproaaide, N-N-diethylcaprylamide, and the like. N-N-dimethyIformamide, hereinafter referred to as DMF, is especially preferred.

/V 4 Other amides which can be employed are the water-soluble amides of carbamic acid, for example, urea, biuret, thiourea, ammonium carbamate, and derivatives of urea such as monomethylolurea and dime thy lolurea. 5 While aqueous solutions of the above-described ^ compounds which provide a mitrogen-containing cation are effective in a treating fluid added to a hot water-containing fluid stream to reduce scale formations and to dissolve scale already formed, it is even more 10 effective to include in the treating fluid a water-N soluble or dispersible polymer. The polymer-containing treating fluid appears to extend the area over which the treating fluid is effective, e.g., scale is removed or prevented from forming over a greater area of the 15 conduit downstream from the point of addition of the treating fluid to the hot water-containing fluid stream.

Suitable water-soluble or dispersible polymers for use in this invention include both natural and synthetic polymeric materials selected from the group consisting 20 of polyacrylamide, partially hydrolyzed polyacrylamide, polyacrylic acid, polyvinyl alcohol, polyvinyl pyrrolidone, polystyrene sulfonate, polyethylene oxide, a heteropolysaccharide produced by b'acteria of the genus Xanthomonas, cellulose derivatives, gums and starches. '■ 25 The molecular weight of these polymers can vary over a wide range, e.g., 10,000 to 25,000,000. Pearl starch is preferred.

Gums are natural or modified polysaccharides or their derivatives that hydrate in water to form viscous 30 solutions or dispersions. Natural gums useful in this invention include seaweed extracts, such as agar, algin, and carrageenan, plant exudates, such as gun arabic, gum karaya, gum tragacanth and gum ghatti; gums from 209694 seeds or roots, such as guar gum, locust bean gum, tamarind gum, psyllium seed gum, quince seed gum, larch gum and pectin; and gums obtained by microbial fermentation, such as dextran and xanthan. Modified gums which 5 may be used include cellulose and starch derivatives a and certain synthetic gums such as low-methoxyl pectin, propylene glycol alginate, triethanolamine alginate, carboxymethyl locust bean gum and carboxymethyl guar gum. Specific cellulose derivatives which may be used are 10 methylcellulose, ethylcellulose, carboxymethylcellulose, and carboxymethylhydroxyethylcellulose. Specific starch derivatives are starches from corn, high-amylose corn, potato, wheat, sorghum, rice, arrow-root, and cassava.

Also included are modified starches, such as thin-boiling 15 starches made by a partial hydrolysis with acid, and oxidized starches made by treating starch with hypochlorite.

The region of the conduit over which the scale-forming materials in the fluid stream begins to flash is approximately the same as the region over which the 20 ammonium or substituted ammonium compounds begin to flash. However, the two regions do not overlap each other exactly. In laboratory tests to be described later, it is determined that in the absence of any treating materials, most of the scale from the scale-25 forming materials deposits in a conduit near where these materials begin to flash. When a solution of an ammonium or substituted ammonium compound is added to the system, there is soine effect in inhibiting formation of scale, dissolving scale already deposited, and inhibiting corrosion.

When an aqueous solution of a polymer is added to the fluid stream in the absence of a compound which provides a nitrogen-containing cation, there is little % 30 / 2 096 94 effect in inhibiting formation of scale, dissolving scale already deposited or inhibiting corrosion. However, the scale is deposited more uniformly over the surface of the conduit from the point where flashing begins to the upper end of a vertically positioned conduit rather than being concentrated near the point where flashing begins.

When the fluid stream contains a solution of both a compound which provides a nitrogen-containing cation and a polymer, formation of scale is inhibited, scale previously deposited is dissolved, and corrosion is inhibited. Thus, it appears that the polymer expands the region over which both the scale-forming components and the compound which provides a nitrogen-containing cation flash.

A lesser amount of the treating agent mixture is required to remove a scale than to inhibit its deposition. When a scale is deposited from a fluid stream, it is believed that only a small proportion of the potential scale-forming components actually flash and form scale with the remainder passing on through the conduit. Zf it is desired to inhibit scale formation, treating material is preferably added to the fluid stream continuously throughout the entire operation.

The invention is further illustrated by the following examples which are illustrative of various aspects of the invention and are not intended as limiting the scope of the invention as defined by the appended claims. 2 098 94 EXAMPLES 1 TO 49 A series of laboratory tests is made to simulate the scale build-up caused by the flashing of a brine to steam when passing through a conduit. A vertically positioned conduit is made up of eight axially aligned sections of 0.563 inch outside diameter, 0.359 inch inside diameter, 4 inches long type 316 stainless steel coned and threaded nipples attached with type 316 stainless steel couplings. The conduit is wrapped first with aluminum foil, next with a heating tape and finally with a layer of glass wool insulation. The tube is partially filled with distilled water, the heating tape is turned on, and the temperature of the conduit itself rises to 325° F. When the distilled water begins to boil, a 500 milliliter or 2,000 milliliter sample of a potentially scale-forming test solution is slowly and continuously fed into the bottom of the conduit via a U tube and passed upwardly therethrough. As the test solution boils, the feed rate is adjusted to maintain the liquid level at about the midpoint of the conduit. The vapors generated pass out the top of the conduit and into a rubber tubing attached to a condenser where they condense. The resulting liquid is collected and visually observed. It takes about one-half hour and about four hours, respectively, for the 500 milliliter and the 2,000 milliliter samples to pass through the conduit. When all of the test solution has been introduced into the conduit, it is followed by 100 milliliters of 5 percent by weight sodium chloride brine. The heating tape is turned off. The insulation, heating tape and aluminum foil are removed, and the conduit allowed to cool to ambient temperature. The conduit is disassembled and the interior thereof visually ? '■V-' examined for the presence of scale. When some scale is observed to be formed/ the interior of the conduit is contacted with an aqueous solution of 4 1/2 percent by weight hydrochloric acid to dissolve the scale. The 5 amount of scale present is determined by titration with a 0.01 molar aqueous solution of the tetra sodium salt of ethylenediamine-tetraacetic acid using the dye Erichrome Black T as an indicator. The results of these tests are given in Table 1. : v*\-7 v ) TABLE 1 SCALE INHIBITION IN A CONDUIT O Aqueous Brine Containing 5t by Wt. WaCl, Saturated with CO.., and also containing the following; Example Size of Sample Number (milliliters) CaCl.

NaHCO. nh4ci (gms/liter) (gms/liter) (gms/liter) Polymer (gms/liter) Equivalents of Ca++ Ion Deposited on the Conduit Wall 1 500 1.110 1.680 none none 0.00349 2 2,000 0.2775 0.420 none none 0.00507 3 500 1.110 1.680 0.268 none 0.00352 4 2,000 0.2775 0.420 0.268 none 0.0006 500 1.110 1.680 0.535 none 0.00247 6 500 1.110 1.680 0.803 none 0.00177 7 500 1.110 1.680 1.070 none 0.00085 8 500 1.110 1.680 none 0.2 Xanthan Gum* 0.00345 9 500 1.110 1.680 none 0.2 Partially hy- 0.00302 drolyzed polyacrylamide 500 1.110 1.680 none 0.2 polyacrylamide 0.00415 11 500 1.110 1.680 0.268 0.2 Xanthan Gum* 0.00247 12 500 1.110 1.680 0.535 0.2 Xanthan Gum* 0.00195 13 500 1.110 1.680 0.803 0.2 Xanthan Gum* 0.00006 14 500 1.110 1.680 1.070 0.2 Xanthan Gum* 0 500 1.110 1.680 1.070 0.025 Xanthan Gum* 0.00024 16 500 1.110 1.680 1.070 0.05 Xanthan Gum* 0 17 500 1.110 1.680 1.070 0.2 Xanthan Gum* 0.00117 18 500 0.555 0.840 0.535 0.05 Partially hy- 0 hydrolyzed polyacrylamide 19 500 1.110 1.680 1.070 0.05 Partially " 0.000325 2,000 0.2775 0.840 0.2675 0.2675 Guar Gum 0 21 2,000 0.2775 0.420 0.2675 0.0125 Guar Gum 0 22 2,000 0.2775 0.840 0.2675 0.0125 Guar Gum 0.00384 23 2,000 0.2775 0.840 1.070 0.0125 Guar Gum 0.000075 24 2,000 0.555 0.420 0.2675 0.0125 Guar Gum 0 2,000 2.22 0.420 0.2675 0.0125 Guar Gum 0.000135 26 500 1.110 1.68 1.070 0.025 Guar Gum 0.000335 27 2,000 0.2775 0.840 0.2675 0.025 Guar Gum 0.00515 Reduction in in Scale Formation (%) 0 98.8 29.2 49.3 75.6 0 23.1 0 14.9 44.1 98.3 100 93.1 100 70.1 100 90.7 100 100 24.3 98.5 100 97.3 90.4 0 NJ O I *Kelqan, etc. continued CJ ' ; O1 TABLE 1 (continued) SCALE INHIBITION IN A CONDUIT Aqueous Brine•Containing 5% by Wt, NaCl; Saturated with CO^• and also containing the following: CaCl- NaHCO. nh4ci Example~Si'4frof Sample v'av',"2 ""*"*^3 Number (milliliters) (gms/liter) (gms/liter) (gms/liter) Polymer (gms/liter) Equivalents of Reduction in Ca++ Ion Depo- in Scale sited on the Formation Conduit Wall 28 500 1.110 1.68 1.070 0.05 Guar Gum 0 100 29 2,000 0.555 0.840 0.535 0.05 Guar Gum 0 100 500 1.110 1.68 1.070 0.2 Guar Gum 0 100 31 2,000 0.2775 0.420 0.2675 0.0125 Corn Starch 0 100 32 2,000 0.2775 0.840 0.2675 0.0125 Corn Starch 0 100 33 2,000 0.2775 0.840 0.2675 0.0125 Corn Starch 0.00273 46.1 34 2,000 0.2775 0.420 0.2675 0.025 Corn Starch 0.00423 16.6 2,000 0.2775 0.420 0.2675 0.025 Modified 0.00064 86.7 Starch 36 500 0.555 0.840 0.535 0.5 Modified 0.00064 86.7 Starch 37 500 0.555 0.840 0.535 0.025 Carboxy 0.000785 77.5 methylcellulose 100 38 500 1.110 1.68 1.070 0.2 II M 0 39 500 1.110 1.68 1.070 0.2 Hydroxy- 0 100 ethylcellulose 100 40 500 1.110 1.68 1.070 0.05 Kelzan X-C 0 41 500 1.110 1.68 1.070 0.025 Kelzan X-C 0.00006 98.28 42 500 1.110 1.68 1.070 0.025 Guar Gum 0.000335 90.40 43 500 1.110 1.68 1.070 0.05 Pusher 1000 0.000325 90.69 44 500 1.110 1.68 1.070 0.05 Guar Gum 0 100 45 500 0.555 0.840 0.535 0.025 CMC 0.000785 77.51 46 500 0.555 ,0.840 0.535 0.05 Pusher 1000 0 100 47 500 0.555 0.840 0.535 0.05 Kelzan X-c 0.000575 83.52 48 500 0.555 0.840 0.535 0.058 Staley M. Starch 0.00064 86.66 49 500 0.555 0.840 0.535 0.05 Polyvinyl Ale. 0.0010 71.35 i NJ I* 2096 94 In Examples 1 and 2 in which the test solution contains scale-forming ions but no treating agents, the scale formed forms principally in the portion of the vertically-positioned tubing in the vicinity of the 5 liquid level. In Examples 3 to 7 in which the test ^ solution contains an ammonium compound as a treating agent but no polymer treating agent, a substantial reduction in scale formation is achieved. In Examples 8 tp 10 in. which the test solution contains various 10 polymer treating agents but no treating agent which v provides a nitrogen-containing cation, there is negligible effect in inhibiting scale formation. However, it is observed that the scale formed extends uniformly from the liquid level to the top of the vertically-positioned 15 tubing. In Examples 11 through 49 the test solution contains various concentrations of both various coapounds which provide a nitrogen-containing cation and various polymers. The reduction in scale formation is generally excellent, except in examples 11 and 22, where the 20 concentration of treating agent is not high enough to prevent appreciable scale formation. The reason for the poor results of Test 34 is xipt understood.

While the aforementioned tests are carried out using stainless steel equipment, similar tests using x 25 carbon steel conduits show that the treating solution employed in this invention is not unduly corrosive to carbon steel. The corrosion can be further reduced by incorporating a buffering agent into the treating solution. Geothermal fluids usually contain a substantial concentration of hydrogen carbonate ions which act as a buffer. If a large volume of treating solution is to be employed relative to the amount of geothermal fluid produced, it is preferred to add an alkali metal hydrogen carbonate as a buffering agent to the treating solution. 2096 94 -23-EXAMPLE 50 A geothermal well has a total depth of 5,149 feet and is equipped with 9 5/8-inchdiameter casing to 2,312 feet and 7-inch diameter casing from 2,312 feet to total 5 depth. The well initially produces about 680,000 pounds per hour of geothermal fluid at 150 psi with a 28.4 weight percent steam fraction. After about one month's production, the production declines to about 232,000 pounds per hour of brine at 68 psi with 27.5 weight 10 percent steam fraction. The reason for this decline in production is believed due to the formation and buildup in the casing and in the producing reservoir in the vicinity of the well of calcite scale to the point where further flow of geothermal fluid through the casing and 15 the reservoir is restricted. Probes run down the casing indicate scale build-up around the 2,312 foot level in the well where the 9 5/8-inch diameter casing connects to the 7-inch diamter casing and below. It is estimated that the casing contains about 33,000 pounds of calcite 20 scale.

At the surface, 426 barrels of a treating agent concentrate are prepared by adding to fresh water 1 pound per gallon of ammonium chloride and 0.0568 pound per ^ gallon of sodium bicarbonate buffering agent. Thus, the 426 barrels of treating agent concentrate contains 17,857 pounds of ammonium chloride and 992 pounds of sodium bicarbonate. There is injected down the well under vacuum at a rate of 17 barrels per minute a treat-7J ing agent solution comprising a mixture of the treating agent concentrate and additional fresh water in the ratio of 1 gallon of the treating agent concentrate to 6 barrels additional fresh water. A total of 103,800 barrels of 94 treating agent solution is injected. The well is shut in for 10 hours. During the shut in period, a series of probes having various diameters is lowered down the casing, and the depth each probe reaches before encountering an abstacle (scale) is determined. After this length of time, the well is opened and begins to flow. The mass flow rate following the treatment increases to 164 percent of the flow rate prior to the treatment. The series of probes are again lowered down the casing on both the 15th and 32nd day following the treatment.

It is found that the scale is substantially removed from the casing over the interval from 2,485 feet to 3,720 feet during the 25 days of production following the treatment. After 7 additional days of production, there is no additional scale build-up. From the difference in depth to which the probes could be lowered 25 days following the treatment, compared to just after the treatment, it is calculated that the treatment removes 18,132 pounds of scale from the casing.

TABLE 2 Probe Diameter (Inches) • * 6 4 3 1.5 MAXIMUM DEPTH TO WHICH PROBE IS LOWERED (FEET) During the 25 days 32 days Shut In Following Following Period Treatment Treatment 2485 3113 3680 3681 3692 2290 3720 3720 3720 3720 2290 3720 3720 3720 3720 209694 Normally, the geothermal fluid produced contains less than 1 percent of noncondensable gases (carbon dioxide). During the 32-day period following the treatment, the produced geothermal fluid contains in excess of 10 percent 5 of noncondensable gases. This indicates that during this period the scale inhibition reaction between ammonium chloride and the bicarbonate ion to form carbon dioxide is still taking place. This continuing inhibition of scale build-up confirms the finding of the probe measure-10 ments.

EXAMPLE 51 In another similar geothermal producing well, the production rate declines to approximately 1/3 of the initial production rate after being produced one month. 15 A drilling bit is run down the casing through the interval over which probes indicate scale to have formed. A 3/4-inch diameter coiled tubing is run down the clean casing to just above the producing interval and anchored in place. An aqueous treating solution is prepared by adding to 20 fresh water 3 pounds per gallon of ammonium nitrate and 0.3 pound per gallon of pearl starch. The well is returned to production and simultaneously and continuously the ^ aqueous treating solution is injected down the coiled tubing at the rate of 1 gallon per minute. The treating 25 solution mixes with the produced geothermal fluid near the producing interval and the resulting mixture of fluids flows up the casing and out of the well. Throughout ^ 6 months of production while treating the well in this manner, a high production rate is maintained. This 30 indicates that no appreciable amount of scale is being formed in the casing during production. 2096 9" -26-EXAMPLE 52 In a geothermal well similar to those described in the previous two examples, an initial high production rate falls considerably after the well is produced about > 5 1 month. It is suspected that calcite Scale may be forming in the well casing. A 3/4-inch diameter coiled tubing is run into the well to just above the producing formation and anchored near the bottom thereof. While the well is being produced there is injected down the coiled 10 tubing 1 gallon per minute of an aqueous solution containing 2 pounds per gallon ammonium chloride. The treatment is continued for 10 days, during which time the concentration of the ammonium chloride in the aqueous treating solution is gradually increased until there 15 is being injected 1 gallon per minute of an aqueous solution containing 6 pounds per gallon fo ammonium chloride. After the 10-day treatment, the production rate increases to about 685,000 pounds per hour of geothermal fluid. This indicates that the scale is 20 substantially completely removed. Treatment of the well with 1 gallon per minute of an aqueous solution containing 2 pounds per gallon of ammonium chloride during subsequent production of the well maintains the casing essentially free of calcite scale.

While various specific embodiments and modifications of this invention have been described in the foregoing specification, further modifications will be apparent 7) to those skilled in the art. Such further modifications cure included within the scope of this invention as defined 30 by the following claims:

Claims (34)

WHAT WE CLAIM IS;

1. A method for treating a fluid stream passing through a conduit, which fluid stream contains liquid hot water and which water contains dissolved salts^, to inhibit formation of scale in the conduit and/or dissolve scale previously formed, comprising: (a) mixing with said fluid stream an effective amount of a treating agent comprising a Water-soluble compound which provides a nitrogen-containing cation capable of flashing to become a gas at high temperatures, selected from the group consisting of ammonium halides, ammonium salts of inorganic acids, ammonium salts of organic acids, ammonium salts of alpha hydroxy organic acids, quaternary ammonium halides, quaternary ammonium salts of inorganic acids, quaternary ammonium salts of organic acids, amine hydrochlorides, amine salts of inorganic acids, amine salts of organic acids, and amides, (b) flashing at least a portion of the liquid net water to steam.

2. The method defined in Claim 1 wherein said fluid stream also contains steam.

3. The method defined in Calim 1 wherein said fluid stream is from a subterranean reservoir.

4. The method defined in Claim 3 wherein said fluid stream is a geothermal fluid stream.

5. The method defined in Claim 1 wherein the liquid hot water is at a high enough temperature so that at ^Baet a portion of the liquid water flashes to steam wh$n the pressure of the fluid stream is decreased.

6. The method defined in Claim 5 wherein the fluid tream is at a temperature of ebe»t 400 to 700° F. and -28- a pressure of -about 400 to 700 psig.

7. The method defined in Claim 1 wherein abont 2 to 50 milliequivalents of a compound which provides a nitrogen-containing cation per liter of the fluid stream is employed.

8. The method defined in Claim 1 wherein abuufe 5 to 10 milliequivalents of a compound which provides a nitrogen-containing cation per liter of the fluid stream is employed.

9. The method defined in Claim 1 wherein the compound which produces a nitrogen-containing cation is added as an aqueous solution.

10. The method defined in Claim 9 wherein the aqueous solution contains about 0.5 to 10 pounds per gallon of the compound which produces a nitrogen-containing cation.

11. The method defined in Claim 1 wherein the ammonium halide is ammonium chloride.

12.. The method defined in Claim 1 wherein the ammonium salt of an inorganic acid . is ammonium nitrate.

13. The method defined in Claim 1 wherein the quaternary ammonium halide is tetramethyl ammonium chloride.

14. The method defined in Claim 1 wherein the amine hydrochloride is butylamine hydrochloride.

15. The method defined in Claim 1 wherein the treating agent also contains an effective amount of a water-soluble or water-dispersible polymer.

16. The method defined in Claim 15 wherein the said polymer is selected from the group consisting of polyacrylamide, partially hydrolyzed polyacrylamide, polyacrylic acid, polyvinyl alcohol, polyvinyl pyrrolidone, —polyatyrene sulfonate, polyethylene oxide, a heteropolysaccharide produced by bacteria, of the genus anthomonas, cellulose derivatives, gums and starches. 209694 10 15 20 25 30 -29-

17. The method defined in Claim 15 wherein the fluid stream contains abaufc 5 to 100 parts per million by weight of the polymer.

18. The method defined in Claim 9 wherein the aqueous solution of the treating agent also contains an effective amount of a buffering agent.

19. The method defined in Claim 9 wherein the aqueous solution of the treating agent contains 0.2 to 0.4 milliequivalents per liter of a buffering agent.

20. The method defined in Claim 19 wherein the buffering agent is sodium bicarbonate.

21. A method for treating a well penetrating a reservoir, producing a fluid stream containing liquid hot water, which water contains dissolved salts, to inhibit formation of a scale in the reservoir in the immediate vicinity of the well, in the well itself, and in the fluid-hand ling equipment associated with the well contacted by the fluid stream and/or dissolve scale previously formed, comprising: (a) mixing with the fluid stream an effective amount of a treating agent comprising a water-soluble compound which provides a nitrogen-containing cation capable of flashing to become a gas at high temperatures, selected from the group consisting of ammonium halides, ammonium salts of inorganic acids, ammonium sialts of organic acids, ammonium salts of alpha hydroxy organic acids, quaternary ammonium halides, quaternary ammonium salts of inorganic acids, quaternary ammonium salts of organic acids, amine hydrochlorides, amine salts of inorganic acids, amine salts of organic acids, and amides, (b) producing the well under conditions at which at least a portion of the liquid hot water flashes to steam. 209G9* -30-

22. The method defined in Claim 21 wherein the fluid stream is a geothermal fluid stream.

23. The method defined in Claim 21 wherein about 2 to 50 milliequivalents of a compound which provides a 5 nitrogen-containing cation per liter of the fluid stream is employed.

24. The method defined in Claim 21 wherein abeufe 5 to 10 milliequivalents of a compound which provides a nitrogen-containing cation per liter of the fluid stream 10 is employed.

25. The method defined in Claim 21 wherein the ammonium halide is ammonium chloride.

26. The method defined in Claim 21 wherein the treating agent is added as an aqueous solution.

27. The method defined in Claim 24 wherein the aqueous solution of the treating agent also contains an effective amount of a water-soluble or water-dispersible polymer.

23. The method defined in Claim 26 wherein the 20 aqueous solution of the treating agent also contains an effective amount of a buffering agent.

29. The method defined in Claim 26 wherein the aqueous solution of the treating agent is injected into the reservoir surrounding the well, the well is shut 25 in until the temperature of the injected aqueous solution of the treating agent approximately reaches the reservoir temperature, and the well is produced.

30. The method defined in Claim 21 wherein the treating agent is injected into the fluid stream at or near the producing interval of the reservoir.

31. The method defined in Claim 1 wherein the compound -which provides a nitrogen-containing cation is JUN1987 «>J|j-N-dime thy 1 f ormamide.

32. The method defined in Claim 21 wherein the compound which provides a nitrogen-containing cation N-N-dimethylf ormamide. 209694 -31-

33. A method according to claim 1 substantially as herein described.

34. A method according to claim 21 substantially as herein described. UNIOH OIL COMPANY OF CALIFORNIA By Their Attorneys HENRY HUGHES LIMITE