NZ729498B2 - Fluro-inorganics for inhibiting or removing silica or metal silicate deposits - Google Patents

Abstract

The present invention generally relates to methods for removing and inhibiting deposits, reducing the pH of aqueous mixtures, and increasing recovery of crude oil from subterranean formations, the methods comprising contacting an acid composition with a liquid that is in contact with a metal surface or with a well or formation. In particular, the present invention relates to the use of an an acid composition comprising nitrogen base salts having a fluoro-inorganic borate or phosphate anion within methods of increasing recovery of crude oil from a subterranean hydrocarbon containing formation and methods of removing inorganic or organic deposit from the internal surface of a well.

Description

FLURO-INORGANICS FOR INHIBITING OR REMOVING SILICA OR METAL SILICATE DEPOSITS FIELD OF THE INVENTION The present invention generally relates to methods for inhibiting and/or removing deposits, reducing the pH of an aqueous ?uid, and increasing production of oil from a subterranean formation the methods comprising ting a composition with a surface in contact with a liquid, wherein the composition comprises a salt of a nitrogen base having a fluoro-inorganic anion. In particular, these methods for removing deposits and lowering the pH can be used in steam tors, evaporators, heat gers, and the like that use water itions containing produced water and other water sources in plant unit operations.

BACKGROUND OF THE INVENTION Within the petroleum industry, acids perform many functions, i.e., removing inorganic and organic , decarbonation, pH adjustment, general cleaning, and disinfecting; r, these acids can be highly dangerous to handle and transport, highly ive to metal surfaces, and can lead to the formation of mineral .

Traditionally, mineral acids such as hydrochloric acid or inhibited hydrochloric acid are used to acidify or neutralize high alkaline water systems. The use of mineral acids can cause corrosion issues of the pipelines and other equipment.

Mineral acids also cause metal loss during cleaning of aqueous systems fouled with deposits and scales in systems contacting the aqueous mixture; the system can be a heat exchangers, cooling or heating system, a pipeline, a water distribution system, or an oil and geothermal well. Some of the waters that may have very high alkalinity must be neutralized prior to their use in order to prevent deposition. Such waters lized with mineral acids will subsequently become very corrosive and cause metal loss due the presence counter ions of the lizing mineral acid.

Silicate-based deposits can occur in many industrial s. For example, silicate-based deposits are a problem in some boilers, evaporators, heat exchangers and cooling coils. The presence of silica/silicate deposits can significantly reduce system thermal efficiency and productivity, increase operating/maintenance costs, and in some cases lead to equipment e. Steam generators and evaporators are especially prone to silicate ts due to ion at elevated temperatures, pH, and increased cycles of concentration (COC).

Chemical treatment programs can be used to minimize deposits, but all the system described above can become fouled over time and cleaning is in order.

Options for cleaning are al u programs or mechanical.

When crude oil production declines, there are a number of causes for the decline in production. Two reasons for a decline in oil production are (1) a reduction in the permeability of the oil "reservoir" or (2) the invasion of this reservoir by the water contained in a lower layer.

A reduction in permeability is typically due to the entrainment of fines, by the ?ow of the oil, towards the production well. Around this well, these particles accumulate and gradually plug the natural pores in the rock. The oil can then no longer ?ow out at an efficient rate through this well. These particles can be of various s (e. g., type of rock, damage to the formation, progressive deterioration of the rock, etc.).

In order to remove these particles and improve the mobility of the oil in the formation, an acidic ?uid can be injected into the well where some of the particles and some of the rock in the formation are partially soluble in this acidic ?uid. Thus, this well stimulation method can cause these particles and rock to partially ve, and make the rock of the formation more porous thereby increasing the mobility of the oil in the ion and increasing well production.

Thus a need exits to develop safe acids to m many functions within the petroleum industry, i.e., removing inorganic and organic scales, decarbonation, pH adjustment, l cleaning, and disinfecting, that are safer to handle and transport than conventional acids.

SUMMARY OF THE INVENTION One aspect of the invention is a method for removing a silica or a silicate deposit or for inhibiting silica or silicate deposition sing ting a cleaning composition with a surface. The e is in contact with a liquid containing a silica or a silicate and having a silica or a silicate deposit or being susceptible to forming a silica or a silicate deposit. The cleaning composition comprises an antifoaming agent and a salt of a nitrogen base having a fluoro-inorganic anion.

WO 33259 2015/047065 Another aspect of the invention is a method for reducing the pH of an s system by contacting the surface of a piece of equipment with an acid ition, wherein the acid ition comprises a salt of a nitrogen base having a ?uoro-inorganic anion.

Yet another aspect is a method for reducing the pH of an aqueous system comprising contacting an acid composition with an aqueous mixture that contacts an internal surface of a piece of equipment. The acid composition can comprise a salt of a nitrogen base having a ?uoro-inorganic anion.

A further aspect of the invention is a method for increasing recovery of crude oil from a subterranean arbon-containing formation, the method comprising injecting an acid composition comprising a salt of a nitrogen base having a ?uoro- inorganic anion into a well which is in contact with the subterranean hydrocarbon- containing formation.

Yet another aspect of the invention is a method for removing an inorganic or organic deposit by contacting an acid composition with an internal surface of a well, the surface being in contact with a liquid containing deposit-forming species, wherein the acid solution comprises a salt of a nitrogen base having a ?uoro—inorganic anion.

BRIEF PTION OF THE DRAWINGS Figure l is a graph of NCM average vs. pH of various compositions A, D, and F with inhibited I.

Figure 2 is a schematic of an evaporator system based on MVC operation.

Figure 3 is a schematic of the dynamic tory test apparatus.

Figure 4 is a schematic of a pilot scale boiler (PSB) system.

Figures 5A and 5B are pictures of a fouled distributor cap and the same distributor cap cleaned with the ng composition, respectively.

Figure 6 is a graph of the % dissolution of a deposit versus the ng composition concentration in v/v% tested in a laboratory scale experiment described in e 18.

Figure 7 is a graph of the amount of silica and calcium deposit removed in mg/L versus the elapsed time of the cleaning process with the cleaning composition in hours tested in a laboratory scale experiment described in Example 18.

Figure 8 is a graph of the amount of silica, calcium, and aluminum deposit removed in mg/L versus the elapsed time of the cleaning process with the cleaning composition in hours tested in a laboratory scale experiment described in Example 18.

Figure 9 is a graph of silica concentration (in mg/L) removed versus time using a cleaning composition where the silica concentration is volume corrected and uncorrected for on of ?uid to the system tested in a field experiment described in Example 22.

Figure 10 is a graph of aluminum concentration (in mg/L) removed versus time using a cleaning composition where the aluminum concentration is volume corrected tested in a field experiment described in Example 22.

Figure 11 is a graph of calcium concentration (in mg/L) removed versus time using a cleaning composition where the calcium concentration is volume corrected tested in a field experiment described in Example 22.

Figure 12 is a graph of magnesium tration (in mg/L) d versus time using a cleaning ition where the magnesium concentration is volume corrected tested in a field experiment described in Example 22.

Figure 13 is a graph of the ion rate (in average mpy) versus time using a cleaning ition tested in a field experiment described in Example 22.

Corresponding reference characters te corresponding parts hout the drawings.

PTION OF THE PREFERRED EMBODIMENTS The present invention is ed to methods for removing silica or silicate deposits. The cleaning compositions of the invention provide more effective cleaning of deposits, quicker turnaround for equipment, and reduce the need to mechanically clean the affected surfaces of the industrial system. In addition, the cleaning compositions are less hazardous than many alternative cleaning . Further, the cleaning compositions are particularly effective for cleaning boilers, steam generators, and evaporators. For example, the cleaning compositions are useful for cleaning boilers, steam generators, and evaporators that are used to process produced water (SAGD, steam ?ood, etc.).

An aspect of the present invention is directed towards reducing the pH of an aqueous system comprising contacting an acid ition with an internal surface of a piece of equipment, or contacting an acid composition with an aqueous mixture that contacts an internal e of a piece of equipment wherein the acid composition comprises a salt of a nitrogen base having a ?uoro—inorganic anion. These s provide reduced corrosion of metal surfaces, less loss of metal atoms, and reduce the need to mechanically clean the affected es of the . In addition, the compositions are less hazardous than many alternative acids used to reduce pH in aqueous systems. Further, the compositions are particularly effective for preventing carbonate-, oxalate—, phosphate, iron, manganese, sulfate-, and/or silica-based scales on equipment including pipes, tanks, steam generators, heating and g exchangers, and evaporators.

The produced water can be highly concentrated in carbonates, oxalates, sulfates, and silicates that can cause the pH of the aqueous mixture to increase. During the recycling process, the produced water is passed through cooling towers and evaporators where high quality feedwater is produced. The alkalinity and counter ions, i.e. Ca, to carbonates and sulfates, other scale forming ions as well as ive ions such as chlorides are also concentrated, which are prone to forming scales and cause corrosion. Traditionally, acids are used to neutralize this alkalinity but this is done at the risk of exposing the surfaces to acids which are known to be corrosive by their virtue as well as adding more corrosive ions such as chlorides and es. Using the current invention, the alkalinity can be neutralized, C02 can be released, and the risk of corrosion is decreased.

Another aspect of the present invention is directed towards s for increasing recovery crude oil from a subterranean hydrocarbon-containing formation and for removing or inhibiting deposits in wells used for the production of oil and geothermal ?uids. These methods use an acid composition comprising a salt of a en base having a fluoro-inorganic anion. This acid composition is advantageous because it is capable of dissolving a variety of inorganic and organic deposits, is capable of ng the pH in an aqueous environment, and is easier to handle than conventional acid compositions.

This method for removing heavy crude oils trapped in carbonate fields by injecting an acid composition generates carbon dioxide that helps lift the oil h the well. This ent can also nate geothermal production and injection wells by contacting the well with an acid composition comprising a salt of a nitrogen base having a ?uoro—inorganic anion that removes various deposits and increases steam and electricity production.

Additionally, in sandstone ions, the s described herein can restore or improve the natural formation permeability around the re by removing formation damage, by dissolving material plugging the pores or by enlarging the pore spaces. Traditionally, this method involves using a solution generally ed of hydrochloric acid pre?ush, a main treating ?uid (mixture of HCl and HF) and an overflush (weak acid solution or . The treating ?uid is maintained under pressure inside the reservoir for a period of time, after which the well is swabbed and returned to production. Using the ition in this invention, the use of HCl and HF have been eliminated which are known corrosive acids.

Further, in carbonate formations, the methods described herein can create new, highly conductive channels (wormholes) that bypass damage.

These methods can be used for water ?ooding of carbonate fields. During this process, the formations yield water that is high in carbonate ions, which can interact with scaling cations such as calcium, magnesium, strontium, and barium to form thick scales. ng the produced water with an acid can form carbon dioxide and limit the scale formation. However, conventionally used acids are corrosive in nature and could cause corrosion problems in ream unit operations. The methods disclosed herein can be used to liberate carbon dioxide without the ive side effect to downstream processing operations that conventional acids may exhibit.

Yet another aspect of the invention is a method for acid well-bore treatments; the treatment can help remove scale or similar deposits from perforations and well completion components. Conventionally, inhibited acids are used to reduce the corrosion rate; however, the corrosion rate can still be unacceptable. The methods described herein can remove the scale and similar deposits while exhibiting less corrosion than conventional acids, thus ting the well. As detailed above, these methods can rejuvenate geothermal and production wells.

A r aspect of the present invention is directed to a method for removing silica or silicate deposits sing contacting a cleaning composition with a surface the surface having or being susceptible to forming silica or silicate deposits from contact with a liquid containing silica or silicates, wherein the cleaning composition ses a salt of a nitrogen base having a ?uoro-inorganic anion. The cleaning composition can further comprise an antifoaming agent.

The compositions of the present invention can be provided in conjunction with a ?uid or an aqueous medium and can be provided in a ready—to-use form or can be provided as separate agents and the composition can be prepared at the site of the treatment. ing on the nature of use and ation, the composition can be in a form of a concentrate containing a higher proportion the salt of nitrogen base having a fluoro-inorganic anion, the concentrate being diluted with water or another solvent or liquid medium or other components such as the antifoaming agent, organic tor of silica or silicate deposits, corrosion inhibitor, or surfactant before or during use. Such concentrates can be formulated to Withstand storage for prolonged periods and then diluted with water in order to form preparations which remain homogeneous for a ient time to enable them to be applied by conventional methods. After dilution, such preparations may contain varying amounts of the acid composition or cleaning composition, depending upon the intended purpose or end-use application.

The acid composition or ng composition can se a salt of a en base having a ?uoro-inorganic anion.

The ?uoro—inorganic anion can comprise a borate ion, a phosphate ion, or a combination thereof. ably, the ?uoro-inorganic anion comprises a borate ion.

The fluoro-inorganic anion can comprise tetra?uoroborate, orophosphate, or a combination thereof. Additionally, a hydrolysis product of tetra?uoroborate and hexa?uorophosphate comprising ?uorine atoms can also be used.

Preferably, the fluoro-inorganic anion of the acid composition or the cleaning composition comprises tetra?uoroborate.

The acid composition or cleaning composition can further comprise water.

The acid composition or cleaning composition can have the ?uoro- inorganic anion comprise tetra?uoroborate and the nitrogen base comprise urea and the molar ratio of urea to uoroboric acid used to prepare the salt is 1:3 to 5:1, ably 1:2 to 3:1. The nitrogen base (e.g., urea) can react with the ?uoro-inorganic acid (e.g., ?uoroboric acid) to form the salt of a nitrogen base having a fluoro-inorganic anion (e. g., urea tetra?uoroborate). However, the relative amounts and/or concentrations of the ?uoro-inorganic acid component and base component in the compositions of the present invention can vary widely, depending on the desired on of the composition and/or the required cleaning activity. As such, the weight ratios and/or concentrations utilized can be selected to achieve a composition and/or system having the desired cleaning and health and safety characteristics.

The nitrogen base can be urea, biuret, an alkyl urea, an alkanolamine, an alkylamine, a dialkylamine, a trialkylamine, an alkyltetramine, a polyamine, an acrylamide, a polyacrylamide, a vinyl pyrollidone, a polyvinyl pyrollidone, or a combination thereof.

The salt of a nitrogen base having a ?uoro—inorganic anion is disclosed in U.S. Patent Nos. 8,389,453 and 8,796,195 and available cially from Nalco- on as Product No. A.

The methods for increasing recovery of crude oil from a subterranean hydrocarbon-containing ion described herein can have the acid composition be diverted toward a zone of the subterranean hydrocarbon-containing formation that has a lower permeability to ?uid than an adjacent zone.

The subterranean hydrocarbon-containing formation can comprise a sandstone reservoir or a carbonate reservoir.

The subterranean hydrocarbon-containing formation can comprise a carbonate reservoir.

The methods described herein can be used in a well that is an oil well, a geothermal well, a al well, and a reinjection well.

The internal e in contact with the acid ition or cleaning composition can be an internal surface of a piece of equipment. This piece of equipment could be a steam generator, an evaporator, a heat exchanger, a cooling coil, a tank, a sump, a containment vessel, a pump, a distributor plate, or a tube bundle.

The piece of equipment whose internal surface is cleaned in the method described herein could also be a pipe, a drain line, or a ?uid transfer line.

Preferably, the piece of equipment cleaned using the methods bed herein is an ator or a steam generator.

The evaporator or steam generator can be used in a geothermal surface system, a thermal recovery system, a sugar production system, or an ethanol production system.

The thermal recovery system can be a steam-assisted gravity drainage , a steam ?ood , or a cyclic steam stimulation system.

When the acid composition is used in a sugar tion system, the acid composition inhibits or removes deposits including oxalate, silica, phosphate, or carbonate deposits.

When the acid composition is used in a geothermal surface system, the acid composition inhibits or removes deposits including silica, carbonate, or sulfide deposits.

The acid composition or cleaning composition can be used in addition to a pigging process. The g process can be used in a tube , a pipe, a drain line, or a ?uid transfer line where deposits have formed and partially blocked the ?ow of the ?uid through the line. The pigging process comprises placing a device (i.e., pig) that is imately the same diameter as the inner diameter of the line or tube to be pigged and propelling the pig through the line or tube, usually by applying pressure behind the pig. The acid composition or cleaning composition would aid in the pigging process by removing or softening the deposits formed in the lines whereby less pressure is needed to propel the pig through the line or tube and removal of the deposits is increased.

The aqueous system can be a produced water, a surface water, a ground water, a feedwater, or a combination thereof.

The aqueous system can have a basic pH (i.e., a pH > 7).

The acid composition or cleaning composition can reduce corrosion of the internal e of the piece of equipment as compared to the same method using a conventional acid composition (e.g., hydrochloric acid, hydro?uoric acid, sulfuric acid, etc.).

The acid composition or ng composition can reduce metal loss from the internal surface of the piece of equipment as ed to the same method using a conventional acid composition (e.g., hloric acid, hydro?uoric acid, sulfuric acid, etc.).

The acid composition or cleaning ition can further comprise a surfactant. Preferably, the surfactant is a nonionic surfactant.

The acid ition or ng composition can further comprise sodium chlorite/chlorate, and an additional acid. This acid composition can disinfect the aqueous system.

The acid composition or cleaning composition can further comprise a corrosion inhibitor.

The acid composition or cleaning composition can further comprise a chelating agent.

The chelating agent can be ethylene diamine tetraacetic acid , 1- yethane l,l—diphosponic acid (HEDP), a gluconate, or a combination thereof.

The methods for removing an nic or c deposit in a well can remove deposits of a metal oxalate, a metal ate, a silicate, a metal sulfate, or a combination f.

The concentration of the acid used for injection can be from about 5 wt.% to about 30 wt.% based on the total weight of the acid composition.

The concentration of the neat acid composition can be from about 5 wt.% to about 85 wt.%.

For removing deposits in wells, the concentration of the acid composition in the injection mixture can be from about 5 wt.% to about 30 wt.%. Preferably, the tration of the acid ition is about 15 wt.% based on the total weight of the carrier ?uid (e.g., aqueous mixture) that is being ?ushed into a well. After 24 to 36 hours of contact of the aqueous mixture with the well and ion, the mixture is then pumped out of the well or formation.

The method for cleaning the surface in contact with a liquid containing silica or silicates can be performed at a ature from about 0 0C to about 374 0C, from about 20 0C to about 320 0C, or from about 40 0C to about 100 0C.

In particular, the application of the composition can be in the cleaning and rejuvenation of wells which are used for the production of oil and geothermal ?uids and reinj ection of brine and general disposal wells.

The injected ?uid can be, for example, water, brine (salt water), hydraulic fracture stimulation ?uid (i.e. fracking ?uid), acidizing additives, or any other type of aqueous ?uid.

The acid composition can be injected into the formation during almost any stage in the life of the well, such as during drilling, completion, or stimulation. The acid compositions are used in well stimulations methods to help increase permeability and improve production.

Additional additives typically used in hydraulic fracturing or used post- primary fracturing can be injected into the well, such as a ifying agent, a solvent, an , a ?ow back aid, a non-emulsifier, a friction reducer, a breaker, a crosslinking agent, a biocide, or a proppant (e.g., sand). These additives typically are less than 1% of the fracturing ?uid volume.

The injection step of the methods of the invention can occur after lic fracturing of the well.

The injection step of the methods of the invention can occur during hydraulic fracturing of the well.

The antifoaming agent of the cleaning ition can comprise a nonionic silicone (available commercially from Nalco, Inc. as Product No. 336FG), an ethoxylated, propoxylated C14-C13 alcohol (available cially from Nalco, Inc. as Product No. 00PG-007), nonionic alkoxylated CAI-:0 alcohol comprising both ethoxy and pmpoxy groups (available commercially from Nalco, Inc. as Product No. R-50360), nonionic propylene glycol, ne glycol block copolymer (available commercially from Nalco, Inc. as Product No. PP10-3038), an ethoxylated C11-C14 alcohol (available commercially from Nalco, Inc. as Product No.PP10-3148), a propylene oxide glycol r able commercially from Nalco, Inc. as Product No. 7906), a C16-C18 alcohol able commercially from Nalco, Inc. as Product No.7465), or a combination thereof.

Preferably, the antifoaming agent of the cleaning composition comprises a nonionic silicone commercially available from Nalco, Inc. as Product No. 336FG.

The antifoaming agent can be present in the ng composition at a concentration of from about 1 mg/L to about 50,000 mg/L, from about 1 mg/L to about 40,000 mg/L, from about 1 mg/L to about 30,000 mg/L, from about 1 mg/L to about ,000 mg/L, from about 1 mg/L to about 10,000 mg/L, from about 5 mg/L to about ,000 mg/L, from about 5 mg/L to about 5,000 mg/L, from about 5 mg/L to about 1,000 mg/L, from about 5 mg/L to about 500 mg/L, from about 5 mg/L to about 300 mg/L, from about 5 mg/L to about 200 mg/L, from about 10 mg/L to about 10,000 mg/L, from about 10 mg/L to about 5,000 mg/L, from about 10 mg/L to about 1,000 mg/L, from about 10 mg/L to about 500 mg/L, from about 10 mg/L to about 300 mg/L, from about mg/L to about 200 mg/L, from about 50 mg/L to about 5,000 mg/L, from about 50 mg/L to about 1,000 mg/L, from about 50 mg/L to about 500 mg/L, from about 50 mg/L to about 250 mg/L or from about 50 mg/L to about 150 mg/L.

The antifoaming agent is effective at the low pH and very high conductivity of the cleaning compositions, as well as in cleaning solutions containing hardness ions, silica, organics, or heavy metals (e.g., iron) removed from fouled es.

The acid composition or cleaning ition can also include a corrosion inhibitor. The corrosion inhibitor employed in the present invention can be any one or more corrosion inhibitors known to those skilled in the art and/or specifically dictated by several factors including, but not limited to, the type of surface to be treated (metals, such as, aluminum, steel, iron, brass, copper, ceramics, plastics, glass etc.), the tetra?uoroboric acid concentrations thereof included in the system, system pH, the inhibitor efficiency, inhibitor solubility characteristics, desired length of exposure of the system to the surface, environmental factors, etc. Accordingly, such a corrosion tor can be a sulfonate, a ylate, an amine, an amide, a borated-based inhibitor compound, or a combination thereof.

Preferably, the corrosion inhibitor is an imidazoline, a nary amine, a fatty acid, a ate ester, a carboxylic acid, an amine, a ate, a polyphosphate, a heavy metal, or a combination thereof.

Suitable corrosion tors for inclusion in the compositions include, but are not limited to, alkyl, yalkyl, alkylaryl, arylalkyl or arylamine quaternary salts; mono or polycyclic aromatic amine salts; imidazoline derivatives; mono-, di—or trialkyl or alkylaryl phosphate esters; phosphate esters of hydroxylamines; phosphate esters of s; and monomeric or oligomeric fatty acids. le alkyl, hydroxyalkyl, alkylaryl arylalkyl or arylamine quaternary salts include those alkylaryl, arylalkyl and arylamine nary salts of the formula [N+R5aR6aR7aR8a][X_] wherein Rsa, R6a, R", and R831 contain one to 18 carbon atoms, and X is Cl, Br or I. In certain embodiments, R53, R621, R721, and R821 are each independently selected from the group consisting of alkyl (e.g., C1-C18 alkyl), hydroxyalkyl (e. g., C1- C18 hydroxyalkyl), and arylalkyl (e.g., benzyl). The mono or polycyclic aromatic amine salt with an alkyl or alkylaryl halide include salts of the a [N+R53R6BR73R83][X'] wherein Rsa, R63, R", and R8a contain one to 18 carbon atoms, and X is Cl, Br or I.

Suitable quaternary um salts include, but are not limited to, tetramethyl ammonium chloride, tetraethyl um chloride, tetrapropyl ammonium chloride, tetrabutyl ammonium chloride, tetrahexyl ammonium chloride, ctyl ammonium chloride, benzyltrimethyl ammonium chloride, benzyltriethyl ammonium chloride, phenyltrimethyl ammonium chloride, phenyltriethyl ammonium chloride, cetyl benzyldimethyl um chloride, hexadecyl trimethyl ammonium chloride, dimethyl alkyl benzyl quaternary ammonium nds, monomethyl dialkyl benzyl quaternary ammonium compounds, trimethyl benzyl nary ammonium compounds, and yl benzyl quaternary ammonium nds, wherein the alkyl group can contain between about 6 and about 24 carbon atoms, about 10 and about 18 carbon atoms, or about 12 to about 16 carbon atoms. Suitable quaternary ammonium compounds (quats) include, but are not limited to, trialkyl, dialkyl, dialkoxy alkyl, monoalkoxy, benzyl, and imidazolinium quaternary ammonium compounds, salts thereof, the like, and combinations thereof. In certain embodiments, the quaternary um salt is an alkylamine benzyl quaternary ammonium salt, a benzyl triethanolamine quaternary ammonium salt, or a benzyl dimethylaminoethanolamine quaternary ammonium salt.

The corrosion inhibitor can be a quaternary ammonium or alkyl pyridinium quaternary salt such as those represented by the general formula: RgaB_ wherein R93 is an alkyl group, an aryl group, or an arylalkyl group, wherein said alkyl groups have from 1 to about 18 carbon atoms and B is Cl, Br or 1. Among these compounds are alkyl pyridinium salts and alkyl pyridinium benzyl quats. Exemplary compounds e methyl pyridinium chloride, ethyl pyridinium chloride, propyl pyridinium de, butyl pyridinium chloride, octyl pyridinium chloride, decyl pyridinium chloride, lauryl pyridinium chloride, cetyl pyridinium de, benzyl pyridinium and an alkyl benzyl nium chloride, ably wherein the alkyl is a C1- C6 hydrocarbyl group. In certain embodiments, the ion inhibitor includes benzyl pyridinium de.

The corrosion inhibitor can also be an imidazoline derived from a diamine, such as ethylene diamine (EDA), diethylene triamine (DETA), triethylene tetraamine (TETA) etc. and a long chain fatty acid such as tall oil fatty acid (TOFA).

Suitable imidazolines include those of formula: 12 I />_R10a R13a N wherein R1221 and R13a are independently a C1—C6 alkyl group or hydrogen, R1131 is hydrogen, C1-C6 alkyl, C1-C6 hydroxyalkyl, or C1-C6 arylalkyl, and R103 is a C1-C20 alkyl or a C1-C20 alkoxyalkyl group. Preferably, Rm, R12a and R133 are each hydrogen and R1021 is the alkyl mixture typical in tall oil fatty acid (TOFA).

The corrosion inhibitor compound can further be an imidazolinium compound of the following formula: n R1221 and R1321 are independently a C1-C6 alkyl group or hydrogen, R1121 and R1421 are independently hydrogen, C1-C6 alkyl, C1—C6 hydroxyalkyl, or C1—C6 arylalkyl, and R10 is a C1-C20 alkyl or a C1-C20 alkoxyalkyl group. le mono-, di-and trialkyl as well as ryl phosphate esters and phosphate esters of mono, di, and triethanolamine typically contain between from 1 to about 18 carbon atoms. Preferred mono-, di-and trialkyl phosphate esters, alkylaryl or arylalkyl phosphate esters are those prepared by reacting a Cg-Clg aliphatic alcohol with phosphorous pentoxide. The phosphate intermediate interchanges its ester groups with triethyl phosphate with triethylphosphate producing a more broad distribution of alkyl phosphate esters. Alternatively, the ate ester may be made by admixing with an alkyl diester, a mixture of low molecular weight alkyl alcohols or diols. The low molecular weight alkyl alcohols or diols preferably e C6 to C10 ls or diols.

Further, phosphate esters of polyols and their salts ning one or more 2- hydroxyethyl groups, and hydroxylamine phosphate esters obtained by ng polyphosphoric acid or phosphorus pentoxide with hydroxylamines such as diethanolamine or triethanolamine are red.

The corrosion inhibitor compound can further be a monomeric or oligomeric fatty acid. Preferred are C14-C22 saturated and unsaturated fatty acids as well as dimer, trimer and oligomer products obtained by polymerizing one or more of such fatty acids.

The acid composition or cleaning composition can also comprise a scale inhibitor.

Suitable scale inhibitors e, but are not limited to, phosphates, phosphate esters, phosphoric acids, phosphonates, phosphonic acids, polyacrylamides, salts of acrylamido-methyl e sulfonate/acrylic acid copolymer (AMPS/AA), phosphinated maleic copolymer (PHOS/MA), and salts of a polymaleic acid/acrylic acid/acrylamido-methyl propane sulfonate terpolymer (PMA/AMPS).

The acid composition or cleaning compositions can ally comprise one or more nonionic, anionic, cationic or amphoteric surfactants or a mixture thereof to improve both mance and economy. The type of surfactant selected can vary, for example, depending on the nature of the particular conditions of use (e. g., type of residue to be d or type of surface), and/or the nature of the solvent (e. g., aqueous versus a less polar solvent such as an alcohol or other organic solvent).

Preferably, the cleaning composition can comprise a ic surfactant.

The ic surfactant can be Videt Q3TM surfactant, which demonstrates rapid wetting due to the ent, associated dynamic surface tension profile and is commercially available from Vitech International, Inc.).

The cleaning composition can further se an organic tor of silica or silicate deposition.

The inorganic or organic inhibitor of silica or silicate deposition can be boric acid, borates, oligomeric and polymeric compounds (e.g., acrylic acid—polyethylene glycol monomethacrylate copolymer (Product No. 3DT155 available from Nalco) and 2- propenic acid, polymer with a 2—propenyl-W-hydroxypoly(oxy-1,2—ethanediyl), sodium salt (Product No. 3DT156 available from Nalco).

The compositions of the t invention can be provided in conjunction with a fluid or an aqueous medium and can be provided in a ready-to-use form or can be provided as separate agents and the composition can be prepared at the site of the treatment. Depending on the nature of use and application, the composition can be in form of a concentrate containing a higher tion the salt of en base having a ?uoro-inorganic anion, the concentrate being d with water or another solvent or liquid medium or other components such as the antifoaming agent, organic inhibitor of silica or silicate deposits, corrosion inhibitor, or surfactant before or during use. Such concentrates can be formulated to Withstand storage for prolonged periods and then diluted with water in order to form preparations which remain homogeneous for a sufficient time to enable them to be applied by conventional methods. After dilution, such preparations may contain varying s of the cleaning ition, ing upon the intended purpose or end-use application.

The piece of equipment whose internal surface is cleaned in the method described herein could also be a pipe, a drain line, a ?uid transfer line, a production well, or a subterranean hydrocarbon containing reservoir.

The method for cleaning the surface in contact with a liquid containing silica or tes can be performed at a temperature from about 0°C to about 374°C, from about 20°C to about 320°C, or from about 40°C to about 100°C.

For an evaporator, the method can be performed at a temperature from about 20°C to about 100°C, from about 40°C to about 100°C, from about 40°C to about 90°C, from about 40°C to about 80°C, or from about 60°C to about 80°C.

For a boiler, the method is performed at a temperature from about 40°C to about 340°C, from about 250°C to about 330°C, or from about 300°C to about 330°C, from about 310°C to about 320°C, or from about 40°C to about 100°C.

The method for removing a silica or a silicate deposit can also remove organic deposits. The c ts that can be removed from the surface can water-soluble organics, bitumen, naphthenic acids, and organics which may be partially thermally degraded.

When the system to be cleaned is off line for cleaning, the method for cleaning the surface in contact with a liquid ning a silica or a silicate can be med using a cleaning composition having a concentration of from about 1 V/V% to about 50 v/v%, from about 3 v/v% to about 25 V/V%, from about 10 V/v% to about 20 V/v%, or about 15 v/v% of the composition containing the salt of the nitrogen base having a fluoro-inorganic anion based on the total weight of the cleaning composition.

] When the piece of equipment is on—line, the acid composition is from about 65 to about 85% active acid concentration in the acid ition and is fed to the system at from about 10 to about 100 ppm of active acid based on the aqueous system volume. Similarly it can be added to other aqueous systems with a chemical feed pump. When the piece of equipment is off-line, the acid composition comprises from about 10 wt.% to about 20 wt.% acid, preferably about 15 wt.% acid in an aqueous mixture and is added to the feed line to directly contact the internal surface of the equipment desired to be cleaned.

Further, when the system is off line for cleaning, the method for cleaning the surface in contact with a liquid containing silica or tes can be med using a cleaning composition having a concentration of from about 1 v/v% to about 50 v/v%, from about 3 v/v% to about 25 v/v%, from about 10 v/v% to about 20 v/v%, or about 15 v/v% of t No. A (available from Nalco—Champion) based on the total weight of the acid composition or cleaning composition.

Additionally, when the system is on-line and a cleaning process using the acid composition or cleaning ition is used, the concentration of the cleaning composition in the feedwater is from about 5 mg/L to about 300 mg/L, from about 30 mg/L to about 300 mg/L, or from about 30 mg/L to about 100 mg/L.

Preferably, when the system is on-line and a cleaning process using the acid composition or cleaning composition, the concentration of the acid composition or cleaning composition in the feedwater is from about 30 mg/L to about 100 mg/L.

In particular, the application site for use of the acid composition or cleaning composition can be four two-stage evaporators running in parallel. The ators operate based on the MVC principle. The primary and secondary stages of each ator operate in series and are housed within the same containment vessel.

One evaporator can be larger than the other three evaporators.

Figure 2 shows the major components in an evaporator system. A vapor compression evaporator (or brine concentrator) 10 can contain various internal structures including tube bundles and brine distributors. The vapor compression ator 10 is ted to a compressor 20, a recirculation pump 30, a deaerator 60 having a vent 62, and a distillate pump 40. Wastewater 52 is fed h a heat exchanger 50 into the deaerator 60 and into the vapor compression evaporator 10. The distillate 42 exits the vapor compression evaporator 10 into a distillate pump 40 and through the heat exchanger 50. The brine is recirculated h the recirculation pump and waste brine exits the waste brine line 32. Steam is compressed by circulating through the compressor 20.

The typical operating characteristics for an evaporator system like the one shown in Figure 2 are detailed in Table 1.

Table l - Typical Operating Characteristics (approx) r Larger Pa ar meter System System Feedwater Flow 250 300 (m3/hr) Tube Bundle Surface 12,000 12000 Area (m ) ter Temp. 0 80 80 Sump Temp. (C) 105 105 Total Distillate 293-294 (m3/hr) Blowdown Rate ~5-6 ~6-7 (m3/hr) Total Cycles of Concentration 45-55 45-55 (target) Falling film MVC evaporators have high heat transfer characteristics and efficiency compared to other evaporator designs (Heins, W. (2008).

Technical ements in SAGD Evaporative Produced Water ent, International Water ence in San Antonio, Texas, October 26-30, -55). A high heat transfer coefficient is required to effectively evaporate the water and increase the temperature (AT ~27°C at ation site) to produce high quality feedwater. Along with the evaporative process, the concentration of nces present in the feedwater can be cycled up as high as 45-55 times their initial concentration. The combination of higher temperature and higher concentrations of inorganic and organic substances increases the probability that the inversely soluble and particulate substances will deposit on wetted portions of evaporator .

Thus, clean heat-transfer surfaces are very desirable for energy- efficient production of distillate from water that contains high levels of inorganic salts and organic contaminants. When deposits form insulating layers on heat-exchanger surfaces of evaporators, a reduction in U-values (heat-transfer coefficient) occurs. While operating conditions of the ator can be adjusted within limits to compensate for the decrease in U-values, low U—values at some point lead to reduction of distillate flow rate and de-rating of the evaporator operation. If insufficient distillate is available for plant operation (feed water for OTSGs and heat ry steam generators (HRSGS)), then bitumen production can be reduced.

] In addition to reducing evaporator ransfer efficiency and corresponding production of distillate, deposits can block heat-transfer tubes, distribution plates, and ?ow channels. System blockages can lead to poor distribution of water, further reduction in distillate production and make cleaning the system, even with mechanical means, very difficult, , labor-intensive, and time-consuming.

In thermal-recovery of bitumen operations, complex mixtures of waters (e.g., produced water, various recycled water streams, and brackish water) are combined to form evaporator feedwater. The ratios of the various water streams and their chemical itions can vary greatly over time. Further, the drive to maximize efficiency of water usage and reduce water discharge via the increased level of water recycling can lead to increasing levels of deposit-forming ions and substances over time.

This is sufficient to impede evaporator operation.

The average evaporator feedwater quality for five months of operation and the impact of operating at total cycles of concentration of 45 are shown in Table 2. The inorganic portion of water chemistry was measured by inductively-coupled plasma (ICP) spectroscopy.

Table 2 - Evaporator ter y and Impact of Cycles of Concentration Concentration (mg/L) Chemistry* Feedwater cycles"< Aluminum (as Al) 0.23 10.4 Calcium (as Ca) 2.24 101 ium (as Mg) 0.58 26.1 Ca + Mg Hardness (as 8.0 360 CaCO3) Silica (as S102) 244 10,980 TOC 760 34,200 * Additional ions at high concentrations in the ter are boron ~29 mg/L, Na+ ~690 mg/L, Cl" ~210 mg/L, and sulfate ~280 mg/L ** Assumes 100% Transport, t formation will result in lower concentrations measured in evaporator blowdown.

Even though evaporator systems are operated at relatively high pH (e.g., feedwater pH is about 10.6, y system pH is about 12.0, and secondary system is about 12.3), the ation of aluminum, hardness, and silica ions shown in Table 2 can and did result in a deposit forming over time. Due to the large volume of feedwater (e. g., 250-300 m3/hour target rate per evaporator) passing through the system, every mg/L of inorganic or organic material that is deposited from feedwater corresponds to 250-300 grams/hour or 2.2-2.6 metric tons/year deposited in each evaporator.

Due to water recycling and the need to maximize water usage, levels of deposit—forming inorganic ions and cs in feedwater increased over time.

When hydroblasting is used to remove internal deposits, the ator system is taken off-line, and cooled and drained of internal aqueous ?uid. An entry hatch is opened and personnel/equipment for lasting taken in to the ator system. Using a high-pressure water wash lance (hydroblasting), high- pressure water is used to remove deposits and scour the al surfaces. The deposits removed from the internal surfaces are collected and taken out of the system for disposal.

A longer high-pressure water lance is used to remove deposits from on the inside (e. g., tube-side) of long tubes in the heat-exchanger (or tube bundle) portion of the evaporator.

After the evaporator is cleaned, the entry port of the system is sealed up and feedwater is added to reach a normal operating level Within the system. The water recirculation pumps are started and steam is typically added to the shell-side of heat—exchanger to heat the recirculating water. The mechanical vapor compression pump is started and the system is placed back on-line.

For the method described herein, the evaporator system is taken off—line, drained of internal s ?uids and allowed to partially cool to an operating range from 0 0C to 60 OC, ably, 40 0C to 60 0C. A distillate or relatively clean water (e. g., utility water) is used to rinse the system by partially g the evaporator system. Water pumps are used to recirculate the rinse water inside the evaporator to help remove residual amounts of water that may contain high levels of deposit-forming substances (e.g., silica, ss ions, aluminum, iron, and the like). The water recirculation pumps are stopped and the rinse water is drained from the ator. The system is then lly filled with distillate or relatively clean water and circulated using the recirculation water pumps. A sample of the recirculating water is chemically tested to ensure any application guidelines for water quality are met. The temperature of recirculating water is measured to ensure that it is in the operating range.

The volume of water in the evaporator system is measured using a water level monitor in order to determine how much concentrated cleaning solution should be added to reach desired concentration of acid ition or cleaning solution (e.g., if water volume inside of evaporator is 85 m3, then 15 m3 of concentrated cleaning solution would typically be added to produce a 15 v/v% concentration of acid ition or ng solution). Also, optionally, an antifoam agent is added to ensure that foaming within evaporator is minimized (e. g., 4 liters of antifoam product into 100 m3 or 100,000 liters of 15 v/v% ng solution would produce about 40 mg/L concentration of antifoam product). Depending on prior experience, more or less antifoam can be added to the cleaning solution. Additional antifoam can be injected into the cleaning solution if an unacceptable level of foaming persists. The tration of the acid composition or cleaning solution is monitored by an acidity titration method to ensure that the target level of cleaning solution is maintained. If the acid composition or cleaning solution concentration is too high, then onal water can be added to the evaporator system. If the concentration of the acid composition or ng solution is too low, then additional concentrated acid composition or cleaning solution can be added. Samples of ulating acid composition or cleaning solution are taken at prescribed intervals and water chemistry is measured by colorimetric analysis, acidity titration, pH, and ICP (inductively-coupled plasma) to determine the ss of cleaning process and to ensure that the concentration of the acid composition or cleaning solution is being maintained within the desired operating limits.

] The temperature, and water level are also ed to ensure that system is operating within required . The system gs are checked to see if evidence of foaming is occurring. If an operating limit is d (e. g., temperature of recirculating cleaning solution reaches recommended maximum limit), then the acid composition or cleaning solution or system operating conditions are adjusted (e. g., additional dilution water is added to cool the recirculating acid composition or cleaning solution and additional concentrated acid composition or cleaning solution is added to maintain the concentration of acid composition or cleaning solution). al analyses of samples of recirculating acid composition or cleaning solution are used to ine when the cleaning process is completed (e. g., levels of deposit-forming ions such silica, hardness ions, aluminum and the like reach a substantially constant level indicating that the cleaning process is complete) and that any corrosion of the internal surfaces of the evaporator by the acid ition or cleaning solution is below the desired operating limits.

Then, the evaporator recirculation water pump is stopped and the acid composition or cleaning solution is drained from the system. Additional rinse water can be added, recirculated and drained as needed to remove residual amounts of acid composition or cleaning solution remaining in the system. The evaporator is then filled with feedwater to reach a normal operating level within the system. The water recirculation pumps are started and steam is typically added to the side of heat- ger to heat the recirculating water, the ical vapor compression pump is started, and the system is placed back on-line.

The used acid composition or cleaning solution drained from the system is disposed. The disposal method can vary based on the ation site. One disposal method is to neutralize the acid composition or cleaning solution with concentrated caustic until an approximately neutral pH is reached. The neutralized acid composition or cleaning solution can be ed of by sending it to an off-site disposal facility. r disposal method is to mix the used acid composition or cleaning solution with other water streams, neutralize the mixture to precipitate silica, hardness ions, and other deposit-forming substances, filter the precipitated solids (which are disposed), and then dispose of the liquid filtrate by injection into deep-well disposal sites. The number and sequence of steps required in the cleaning of the evaporator and the disposal of used cleaning solution can vary depending on the application site and system design.

Having bed the invention in detail, it will be apparent that modifications and variations are possible without departing from the scope of the invention defined in the appended claims.

EXAMPLES The ing non—limiting examples are provided to further illustrate the present invention.

Example 1: Elemental analysis of deposits The al composition of four deposits was determined by a standard composition is of X-ray ?uorescence (XRF) for elemental composition, organics concentration by C/H/N/S elemental analysis, and the concentrations of organics/water of hydration and other volatile substances by heating to 925 0C for defined period of time. The results are shown in Table 3.

Table 3. Chemical composition of deposits Chemistry Deposit #1 t #2 Deposit #3 Deposit #4 Calcium (as CaO) 5% Sodium (as NazO) 3% Aluminum (A1203) . . 3% Chlorine (as Cl) . not detected Magnesium (as MgO) 8% Potassium (as K20) . . 2% Sulfur (as $03) . . . 2% Iron (as F6203) <0.5% Organics <05% 5% 14% Loss at 925 °Ca 20% 17% 25% O—nce-Thru Application -> Evaporator Evaporator Evaporator a Likely due to water of hydration and also includes organics Example 2: Dissolution of materials The test method consisted of weighing several grams (~3 g) of a standard solid into a 4 02. plastic jar. Followed by the addition of 100 mL of distilled water. The test acids were prepared in 5, 10, or 15 wt. % product in distilled water. The cap to the jar was attached and the jar was shaken vigorously several times to completely wet the solid. If necessary, the cap was loosened to vent the build—up of pressure.

During room temperature tests, the jars were shaken ~3 times per week d 1).

During higher temperature tests (75°C except where noted), the jars were stored in a circulating water bath with an integral shaker d 2). ically, s (3 mL) were taken at least one hour after shaking. The samples (2 g) were then syringe filtered through a 0.45 11 filter. Filtered samples were then diluted with 98 mL of distilled water and submitted for solid composition analysis using X-ray ?uorescence (XRF) and X—ray scattering (XRD) methods. Elemental analysis is presented in Tables 4-13.

The acids tested were urea tetra?uoroborate (commercially available from Nalco—Champion as Product No. EC6697A/R-50975, identified as composition A hereinafter), urea sulfate (commercially ble from Vitech International, Inc. as A85, identified as composition B hereinafter), modified urea tetra?uoroborate rcially available from Vitech International, Inc. as Product APW, fied as ition C hereinafter), urea hloride (commercially available from Vitech International, Inc. as Product BJS—I, identified as composition D hereinafter), urea methanesulfonate (commercially available from Vitech International, Inc. as t M5, identified as composition E after), hydrochloric acid (identified as composition F hereinafter), urea tetra?uoroborate (commercially available from Vitech Internationally, Inc. as Product ALB, identified as G hereinafter), and modified urea hydrochloride (commercially available from Vitech International, Inc. as Product BJS-HT, identified as H hereinafter), product N25 60 rcially available from Nalco -Champion, identified as composition I hereinafter), inhibited hydrochloric acid, commercially available from Nalco Champion as N2560, and urea-hydrofuoride hydro?uoride (commercially available from Nalco Champion as Product DC14, fied as composition J hereinafter).

] The solids tested were talc, amorphous magnesium te, aluminum oxide, magnesium oxide, calcium metasilicate, calcium ?uoride, aluminum silicate, magnesium aluminum silicate, magnetite, manganese dioxide, calcium carbonate, barium carbonate, strontium carbonate, barium sulfate, and strontium sulfate.

Table 4. Dissolution of ium silicate hydroxide (talc) using 15 wt. % acid Method 1 Composition Time Element A B C E D Mg as Mg 163 1664 75 97 7 days Si as SiOz 191 4626 81 107 Mg as Mg 300 2390 123 171 23 days Si as SiOz 240 6534 142 171 Mg as Mg 206 2676 338 216 44 days Si as SiOz 134 7249 374 219 Mg as Mg 475 2929 208 253 62 days Si as SiOz 271 7152 195 217 Method 2 Mg as Mg 462 82 459 34 25 2 hours Si as SiOz 1248 80 1283 34 29 Mg as Mg 1332 227 1362 141 111 6 hours Si as SiOz 2693 197 2572 112 104 Mg as Mg 2778 395 3410 280 251 24 hours Si as SiOz 5148 317 5251 280 299 Mg as Mg 447 313 298 48 hours Si as SiOz 297 284 310 Table 5. Dissolution of magnesium silicate hydroxide (?orisil) using 15 wt. % Method 1 Composition Time Element A B C D E Mg as Mg 2688 2808 2777 2760 7 days Si as SiOz 194 6824 121 133 Mg as Mg 2580 2523 2686 2651 23 days Si as $102 99 6519 177 109 Method 2 Mg as Mg 1640 1657 1526 1451 999 2 hours Si as SiOz 2480 119 3713 88 77 Mg as Mg 2104 2338 1990 2343 2213 6 hours Si as $102 3659 174 4440 147 155 Mg as Mg 2103 2152 2093 2189 2136 24 hours Si as SiOz 5090 257 5322 261 270 a‘ Values have units of mg/L.

Table 6. Dissolution of a using 15 wt. % acid Method 1 Composition Time Element A B C D E 7 days Al as A1 65563 269 5598 59 9 16 days A1 as Al 15474 14107 37 days Alas Al 12361 3241 12193 Method 2 6 hours Al as A1 1414 692 1051 299 77 24 hours Al as A1 7233 3467 6236 1782 359 48 hours Al as A1 6519 3234 3‘ Values have units of mg/L.

Table 7. Dissolution of magnesium oxide using 15 wt. % acid Method 1 Composition 14638 ‘ 8786 3‘ Values have units of mg/L.

Table 8. Dissolution of calcium licate using 15 Wt. % acid Method 1 Composition Time Element A B C D E Ca as Ca 7909211 665 9382 10197 9362 2 days Si as SiOz 6925 2149 5635 1910 1102 Ca as Ca 8012 709 9131 10331 9893 16 days Si as SiOz 8101 1053 6661 939 979 Ca as Ca 764 37 days Si as SiOz 377 Method 2 Ca as Ca 6380 1437 6017 4196 3303 6 hours Si as SiOz 5278 855 4191 438 271 Ca as Ca 6448 1428 6754 8083 7337 24 hours Si as SiOz 5568 591 5375 364 293 Ca as Ca 6006 907 6017 7144 6507 48 hours Si as SiOz 6223 391 5026 356 246 Method 3b Ca as Ca 920 1787 4569 4627 4453 1 day Si as SiOz 406 64 783 3017 3709 Ca as Ca 928 5351 6316 6681 5436 3 days Si as SiOz 485 130 828 4260 4265 3" Values have units of mg/L. b' Same as method 2, except temperature was set at 29 OC. Composition C and D were prepared as 5 wt. %.

Table 9. Dissolution of calcium ?uoride using 15 wt. % acid Method 1 ition Time Element A B C D E Ca 98821 1155 191 813 734 7 days F by ISE 5875 1392 13673 1541 765 Ca 878 994 232 758 717 21 days Fby ISE 350 1116 7755 1445 781 Ca 766 860 251 days F by ISE 3" Values have units of mg/L.

Table 10. Dissolution of aluminum silicate with 15 wt. % acid Method 1 Composition Time t A B C D E Al 2323a 56 2252 62 20 7 days Si as SiOz 4545 117 4451 129 38 A1 5114 174 5377 153 37 23 days Si as SiOz 6299 313 6034 253 74 A1 6334 6033 23 days Si as SiOz 7244 6038 Method 2 A1 2162 57 2335 29 26 6 hours Si as SiOz 1247 111 3040 59 50 A1 4803 236 4738 95 78 24 hours Si as SiOz 2928 417 3245 210 167 Method 3b A1 114 17 103 109 10 1 day Si as SiOz 438 34 539 136 18 A1 738 37 585 548 18 3 days Si as $102 1413 72 1432 235 34 3‘ Values have units of mg/L. b‘ Same as method 2, except temperature was set at 29 0C.

Table 11. Dissolution of magnesium aluminum silicate with 15 wt. % acid Method 1 Composition Time Element A B C D E A] 426a 312 351 260 232 8 days Mg 1451 1509 1365 1416 1386 Si as SiOz 5393 206 5302 243 143 A1 605 425 519 368 304 21 days Mg 1387 1509 1319 1411 1291 Si as SiOz 6667 250 6249 264 132 A1 1153 871 days Mg 1777 1637 Si as $102 8325 7864 Method 2 A1 573 429 2 hours Mg 1070 1106 Si as SiOz 4057 4304 A1 812 232 716 538 211 6 hours Mg 1046 846 1060 1137 913 Si as SiOz 3565 214 3548 580 305 A1 898 456 906 809 377 24 hours Mg 1182 1133 1184 1258 1154 Si as SiOz 4811 337 4553 467 388 3‘ Values have units of mg/L.

Table 12. Dissolution of magnetite with 15 wt. % acid Method 1 Composition Time Element A B C D E 7 days Fe 8565a 11549 2996 4060 558 21 days Fe 12409 15214 1972 9329 1524 37 days Fe 16711 20504 2034 13725 Method 2 6 hours Fe 2088 2209 1942 1536 884 24 hours Fe 8268 8069 3737 9599 3334 48 hours Fe 8405 13212 2210 9309 3441 Method 3b A Ac 7 days Fe 10026 4162 22 days Fe 9996 6054 3‘ Values have units of mg/L. b‘ Same as method 2, except temperature was set at 0C. c' Composition was prepared at 5 wt. %.

Table 13. Dissolution of manganese dioxide with 15 wt. % acid Method 1 Composition Time Element A B C D E Al 570a 142 745 80 40 7 days Mn 572 544 3009 759 186 Si as SiOz 667 69 548 44 37 A1 517 208 610 1 19 50 21 days Mn 920 947 5247 1333 290 Si as SiOz 521 81 529 53 46 Method 2 A1 431 161 264 316 49 6 hours Mn 386 248 827 593 365 Si as SiOz 541 47 297 108 31 A1 478 318 477 504 91 24 hours Mn 1165 908 3699 1532 1072 Si as SiOz 483 136 457 323 62 A1 505 395 545 596 130 48 hours Mn 1337 1111 6494 2167 1129 Si as SiOz 468 184 468 378 73 6" Values have units of mg/L.

Example 3: ion rate titration study Various neat acids used in a titration were studied to evaluate their corrosion rates. A test ?uid was prepared by dissolving sodium carbonate (35.3 g) and sodium chloride (14.4 g) in 2 L of distilled water. The test ?uid was then placed in a 5 L beaker with a magnetic stirring bar. The ng rate was adjusted to ensure good mixing without ucing bubbles into the test ?uid. A Nalco Corrosion Monitor (NCM) mild steel and pH probes were installed into the ?uid. The probes were then connected to a 3D TRASAR® controller to record the data. Aliquots of a neat acid were added to the test ?uid and readings were obtained. The titration was continued until the pH of the ?uid was beyond the range of interest. The pH was adjusted to a pH value of 4. The neat acids used in this trial were compositions A, H, and I. Results from this study are shown in Figure 1.

] It should be noted, the NCM probe readings took about nine minutes each, so ion aliquots required at least 20 minutes for equilibration.

Another set of corrosion rate titrations was conducted in as described but with the change that 35.3 g of sodium carbonate and 14.4 g of sodium chloride was dissolved in 2 L of led water. The pH was adjusted to pH 4 with acid.

Example 4: Corrosion rate determination with bar style coupons Mild steel coupons (Nalco Product No. P5035A) were used to evaluate the corrosion rates of various acids and acids in combination with corrosion inhibitors. The test acids were prepared as a 5, 15, or 25 wt.% solution in led water.

The corrosion inhibitors were prepared as a 0.5, 1.0, 2.0 or 3.0 wt.% solution in distilled water. The test ?uid (about 450 mL) was added to a wide mouth plastic bottle (500 mL).

Various amounts of corrosion inhibitor(s) were added to the jar, the jar was capped, and the jar was shaken to mix the two liquids. Three mild steel coupons were attached to a perforated cap by nonmetallic attachments and height adjusted to be suspended below the surface of the ?uid. The coupons were evenly spaced around the cap so they did not contact one another. The ated cap and coupons were led on the wide mouth jar, and the jar was placed in a circulating water bath. The circulating water bath was set at 65, 75, or 90 °C. A plastic tube connected to an airline was then inserted through the center hole of the cap. The air ?ow was set at n 5 to 10 mL/minute.

Coupons were removed, one after each time point (6, 24, and 48 hours), d with a soft plastic er, and rinsed once with distilled water and twice with acetone to dry. Coupons were then placed in a desiccator to equilibrate to temperature.

Following cleaning and temperature equilibration the s were weighed and the corrosion rate was calculated. The corrosion rate was calculated from weight loss of the coupon, exposure time, and surface area of the coupon.

The acid corrosion inhibitors tested were blends of a quaternary amine, a fatty acid, imidazoline, and an alkyl-derivatized imidazoline, phosphate organic phosphates, and zinc or their blends commercially available from Nalco champion as products, EC1509A, EC9374A, ASP542, 3DT129, and the like.

Example 5: r corrosion rate titration study In a third example of corrosion rate titration studies, 176.7 g of sodium carbonate and 72.0 g of sodium chloride were dissolved in 10 L of distilled water. Coupons were pretreated with 10X product for 72 hours at 90°C. Approximately 8 L of the prepared solution was titrated with acid to a pH between 3.8 and 4.0, to eliminate all C02, diluted to 9 L and allowed to equilibrate overnight at 40°C. ing equilibration, the on was r diluted to 10 L and the temperate was raised to 90°C. Coupons and pH and NCM probes were installed in the test cell. Acids used in this study include compositions D and E. Corrosion inhibitors used in this study include blend of organic quaternary amines, tall oil, fatty acid, and the like (commercially available from Nalco Champion as Product TXl6010, identified as composition K after) Four test conditions were setup, D, F, D with K and D with L. After 48 hours, the s were removed, cleaned, and weighed as described in Example 4.

Example 6: Hybrid corrosion rate ination using bar style coupons and composition In a hybrid corrosion rate study, of the previously described Example , was performed. A test ?uid was prepared using 8.8 g of sodium carbonate, 3.6 g of sodium chloride, and 27.153 g of composition D were dissolved in 500 mL of distilled water. The pH of the equilibrated solution was 3.06. The solution was added to a wide mouth plastic bottle and the coupons (Nalco P5035A) were attached evenly around a perforated cap. The bottle was capped and an e was attached with a ?ow rate of 5 mL/minute with 100% ty. The study was conducted a ature of 750C. The corrosion rate was measured in millimeters per year (mmpy) and mils per year (mpy).

Table 14. Corrosion rate of composition D Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.005 0.43 17 0.041 1 0.88 35 3 D 0.0484 0.52 20 Example 7: Hybrid corrosion rate determination using bar style coupons and composition A hybrid corrosion rate study was conducted in as described in Example 6 with the exception that 40.0046 g of composition A was used in the test ?uid. The pH of the solution was 3.75.

Table 15. Corrosion rate of ition A Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.0139 1.19 47 0.0614 1.32 52 3 A 0.1239 1.33 52 Example 8: Hybrid corrosion rate determination using bar style coupons and composition ] A hybrid corrosion rate study was conducted as described in e 6 with the exception that 16.535 g of composition B was used in the test ?uid. The pH of the solution was 3.75.

Table 16. Corrosion rate of composition B Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.0083 0.71 28 0.0144 0.31 12 3 B 0.0241 0.26 10 Example 9: Hybrid corrosion rate determination using bar style coupons and composition A hybrid corrosion rate study was ted as described in Example 6 with the exception that 43.89 g of composition F was used in the test ?uid. The pH of the solution was 3.75.

Table 17. Corrosion rate of ition F Weight Loss Coupon Composition Corrosion Rate mmpy mpy 2 F 0.0531 1.14 45 3 F 0.0694 0.74 29 Example 10: Corrosion rate determination using bar style s, composition B, and a corrosion inhibitor A corrosion rate determination study was conducted using bar style coupons, an acid, and a corrosion inhibitor. A 15 wt. % of composition B was ed by adding 75 g of composition B to 423 g of distilled water. To that 2.5 g of composition H was added. The solution was the added to a wide mouth plastic bottle and the coupons (Nalco ) were attached evenly around a perforated cap. The bottle was capped and an airline was attached with a ?ow rate of 5 mL/min with 100% humidity. The study was conducted a temperature of 75 0C.

Table 18. Corrosion rate of composition B Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.0203 1.74 69 0.1939 4.16 164 3 B 0.5833 6.26 246 Example 11: Corrosion rate determination using bar style s and ition E A corrosion rate determination study was performed as described in Example 6 with the exception that 75 g composition E and 420 g of distilled water were used.

Table 19. Corrosion rate of composition E Weight Loss Corrosion Rate 0.4012 8.61 0.6706 7.20 Example 12: ion rate ination using bar style coupons, composition C, and a corrosion inhibitor A corrosion rate determination study was performed as described in Example 9 with the exception that 75 g composition C, 5 g of composition 1, and 420 g of distilled water were used.

Table 20. Corrosion rate of composition C Weight Loss Coupon Composition Corrosion Rate mmpy mpy 3 C 2.0134 21.61 851 e 13: Corrosion rate determination using bar style coupons, composition C, and a corrosion inhibitor A corrosion rate determination study was performed as described in Example 9 with the exception that 75g ition C, 5 g of composition 1, and 415 g of distilled water were used.

Table 21. Corrosion rate of composition C Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.4155 35.68 1405 2 C 1.2291 26.38 1039 3 C 1.8319 19.66 774 Example 14: Corrosion rate determination using bar style coupons and composition D A corrosion rate determination study was performed as described in Example 9 with the exception that 75 g composition D, no corrosion inhibitor, 425 g of led water, and 8.24 g sodium de were used.

Table 22. Corrosion rate of composition D Example 15: Corrosion rate ination using bar style coupons and composition A A corrosion rate determination study was performed as described in Example 9 with the ion that 75 g composition A, no corrosion inhibitor, 425 g of distilled water, and 4.12 g sodium chloride were used.

Table 23. Corrosion rate of composition A Weight Loss Coupon Composition Corrosion Rate mmpy mpy l A 0.382 2.88 113 2 A 0.15 3 .22 127 3 A 0.33 12 3 .55 140 Example 16: ion rate determination using bar style coupons and composition B A corrosion rate ination study was performed as described in Example 9 with the exception that 75 g composition B, no corrosion inhibitor, 425 g of distilled water, and 4.12 g sodium chloride were used.

Table 24. Corrosion rate of composition B Weight Loss Coupon Composition Corrosion Rate ___-"my 2 B 0.3275 7.03 277 3 B 0.66 7.08 279 Example 17: Corrosion rate ination using bar style coupons and composition E A corrosion rate determination study was performed as described in e 9 with the exception that 75 g composition E, no corrosion inhibitor, 425 g of distilled water, and 4.12 g sodium chloride were used.

Table 25. Corrosion rate of composition E Weight Loss Coupon Composition Corrosion Rate mmpy mpy 0.0815 6.14 0.304 6.53 3 E 0.7726 8.29 326 Example 18: Lab scale test The cleaning composition used in these tests was a 15 v/v% of composition A in water.

A simple laboratory bench unit was ed and built to evaluate new cleaning chemistries under c conditions. This laboratory bench unit is represented by Figure 2. The deposit 250 for testing was placed in a testing reservoir 240 that was in ?uid connection with the cleaning solution oir 230. The cleaning solution reservoir 230 is placed in a temperature controlled water bath 210. The cleaning solution can be pumped through a pump 220 from the ng solution reservoir 230 to the testing reservoir 240.

The testing apparatus evaluated various cleaning chemistries to obtain data with respect to performance and possible cleaning methods (including temperature, concentration, and time). Additionally, programs and recommendations can be developed for specific deposits. The s translated to improved field performance.

Figure 3 is a schematic of the laboratory scale c test apparatus.

The test method consisted of holding the ng solution at a constant temperature while recirculating the cleaning composition across a field deposit sample. The field samples used for the experiment were analyzed for composition and then dried at 105 °C. Initial sample weight was taken on the dried, as-received deposit.

The deposit sample or object with deposit adhering to it was ed in ?owing cleaning on for the prescribed test period. The cleaning solution could be heated with test temperatures of 60 0C or 80 0C typically used. The entire container for deposit sample could also be immersed in the heating bath. When the test was completed, the remaining deposit was rinsed with deionized water and blotted dry. The recovered residual deposit was then dried at 105 °C. The final weight of the dried deposit was taken and used to determine % dissolution. ts of test on could be d during the test to evaluate ion concentrations using ICP spectroscopy and measure treatment performance as cleaning progresses. This procedure allowed for multiple cleanings, varying temperatures and times.

The test method consisted of holding the cleaning solution at a constant temperature while recirculating the cleaning composition across a field deposit sample. The field samples used for the experiment were analyzed for composition and then dried at 105 OC. Initial sample weight was taken on the dried, as-received deposit.

The deposit sample or object with deposit adhering to it was immersed in ?owing cleaning solution for the prescribed test period. The cleaning solution could be heated with test temperatures of 60 0C or 80 0C typically used. The entire container for deposit sample could also be immersed in the heating bath. When the test was completed, the remaining deposit was rinsed with zed water and blotted dry. The recovered residual t was then dried at 105 OC. The final weight of the dried deposit was taken and used to determine % dissolution. Aliquots of test solution could be removed during the test to evaluate ion concentrations using ICP spectroscopy and e treatment performance as cleaning progresses. This procedure allowed for le ngs, g temperatures and times.

In the situation where a larger object (e. g., water distributor cap) with t on it needed to be , the sample container was enlarged to allow the entire specimen to be immersed in the recirculating cleaning solution. Figures 5A and 4B e and after pictures) of the evaporator water distributor cap showed exceptional cleaning ability of the cleaning composition. No mechanical cleaning was used on distributor cap.

Lab studies to measure dissolution of metal silicate and organic-based evaporator deposits from application site were conducted. Figure 6 showed that deposit dissolution results were strongly ent upon the concentration of cleaning solution (0-15 v/v%). Very good results of 85% dissolution of deposit removal occurred with 15 v/v% concentration of the cleaning composition were obtained at 60 0C after 22 hours.

Figure 7 showed that hardness ions and silica were rapidly released from an evaporator deposit sample on the water distributor cap during the first five to ten hours of treatment at 60 °C. This rapid deposit dissolution period was followed by a lower dissolution rate from 10 to 22 hours as almost all of t was dissolved and more resistant portions of deposit were attacked.

Figure 8 demonstrates that the sump t dissolution with the cleaning composition shows similar trends as Fig. 6 (distributor cap deposit dissolution). e 192 Deposit dissolution testing Due to the different compositions, particle sizes, and surface areas, each of the deposits were ground with a mortar and pestle and then sieved through a #14 sieve so each of the samples would have similar particle size and surface area. Each test solution was prepared by placing 500.00 grams of each solution in a sealable high density polyethylene (HDPE) bottle of known weight. The solution was mixed with a two inch n stir bar of known weight on a stirrer hot plate set to a temperature of 55—60 °C and a mix speed of 5.5 for 90 minutes before 5.0 grams of scale deposit was added.

The scale t (5.0 g) was added to the preheated. test solution and mixed for 16 hours at the same temperature and mix speed. After l6 hours the solution was filtered through filter papers of known weight using the vacuum filtration system.

The filter paper and HDPE bottles were dried in the forced air oven until dry. The dry weights of the bottle, stir rod, and filter paper were recorded. The percentage of dissolved material was then calculated as follows: Percentage t Dissolved = {[lnitial Scale weight Total Residue Weightfl’RWH/lnitial Scale l‘t 100 Table 26. Deposit dissolution results % % % % Cleaning Chemistry Dissolved ved Dissolved Dissolved t #1 Deposit #2 Deposit #3 Deposit #4 Composition A 80% 91% 80% 69% Example 20: Pilot Scale Boiler Tests Pilot Scale Boiler (PSB) equipment is used to evaluate efficacy of ent chemistries and combinations of those treatments. The equipment is also used to evaluate impact of changes in water quality and operating conditions. PSB equipment is designed to provide a rapid tion (within five days) of long-term behavior in larger plant unit ions.

The PSB of Figure 4 has feedwater fed from feed tanks 310, a pump ting the feed tanks 310 to the deaerator 320, a boiler ter (BFW) pump 330 connecting the deaerator 320 and the boiler 340, a firerod 350 contained in the boiler 340, a condensate exit stream 360 and a blowdown stream 370.

During testing of treatment chemistries and operating conditions, PSB ent was run under more /stressed conditions (water chemistry, heat ?ux, and residence time) than SAGD plant boilers and steam-generators, in order to reduce the time required to determine results (Table 27).

Table 27. Typical comparative operating conditions for PSB test versus OTSG Parameter Pilot Scale Boiler Location #1 Design Drum OTSG Energy Source Electrically-heated Natural Gas fire rod ,340 kPa 9,653 kPa Steam Pressure (1500 psig) (1400 psig) Steam Temperature 314 °C 309 °C Initial Heat Transfer Tube up t 344 OC 0 ___ Wall Temperature up to 361 kW/m2 Heat Flux Refer to footnote ,, (114,000 BTU/?g/hr) 50% Holding Time <2 minutes ~1 5 hours (or Residence Time) ' (estimate) Concentration Cycles (or 5 Steam y (80% y) >*‘Typical heat flux range listed in literature is 47—125 kW/m2 or 15,000-40,000 BTU/ftzlhour (Gwak, K.-W., Bae, W. (2010). A Review of Steam Generation for In -Situ Oil Sands Projects. Geosystem Engineering, 13(3), 114.) Water chemistry used for PSB tests is summarized in Table 28. The tests run at 10 cycles of concentration and the water inside the PSB (measured as blow down) will be 10 X more concentrated in all of the feed water chemistries - if no deposition occurs. The feedwater chemistry and PSB cycles of concentration were chosen to provide blowdown water chemistry that is representative of OTSG blowdown water chemistry in Oil Sands applications. Some plants may have higher or lower concentrations of specific chemistries in OTSG blowdown and PSB tests are readily adaptable to test a wide range of water chemistries and operating conditions.

Table 28. Pilot scale boiler chemistry (mg/L) (feedwater and 10 X cycles of concentration) vs. OTSG* Chemistry of PSB Feedwater X10 Cycles Location #1 Feedwater X 4 Pro - ert (m_ ) C cles* Calcium (as Ca) 1.2 1.2 Magnesium (as Mg) 1.0 < detection limit Silica (as SiO2) 300 100 Sodium (as Na) 2,680 3,920 Chloride (as Cl) 3,870 4,040 Lithium (as Li) 6.0 4.4 Conductivity (uS) 13,500 17,040 pH 10.5 10.3 >"Corresponding to 75% steam quality and assumes no deposition occurs (for comparison) 96:0 As shown in Table 28, the water quality used for PSB tests at 10 cycles of concentration is generally more severe than SAGD on #1 operating at 75% steam quality (4 cycles of tration) and is suitable for doing rated testing with ent such as PSB. Silica volatilization in steam is small (approximately 0.5%) under these operating conditions versus silica concentration in boiler water or blowdown (Nalco , Selective Silica Carryover, Technifax TF-5, 1- 3.). Modifications of water and operating conditions listed above can be made when PSB equipment is used to evaluate operating conditions and treatment programs relevant to a variety of SAGD plant locations or other types of boilers (e.g., package or utility).

Table 29. Pilot scale boiler performance results for variety of treatment options Thermal Deposit Rate Feedwater Treatment Deposition Rate* (mg/hr)"< None 23 1 3 .70 Nalco Product No. 3DT156 ition A** with Nalco Product No. -190 0.42 3DT156 * Lowest values indicate best results ** Concentration of ~30 mg/L as product in feedwater The overall performance results listed in Table 29 indicate that the lowest combination of thermal tion rate and t rate (mg/hr) were obtained using a treatment combination of cleaning solution (at dosage of ~30 mg/L) and surfactant added to feedwater of PSB.

Example 21: Antifoaming agent tests A cleaning composition comprising 15 v/v% composition A in water was used to evaluate the efficacy of various antifoaming agents. The cleaning composition (10 grams) and the prescribed amount of antifoaming agent were added to each test tube. The height of liquid in each test tube was measured in mm and recorded before shaking. Each tube was covered with parafilm, usly shaken for one minute, and the height of foam was ed in mm and recorded. The % foam height after one minute of test on g and one minute of test solution sitting was determined by dividing the foam height by the initial liquid height and multiplying by 100. This % foam height was recorded. The test solution was then allowed to sit for 30 minutes and the foam persistence in the test solutions was recorded as yes or no.

The antifoam agents tested were nonionic silicone (available commercially from Nalco, Inc. as Product No. 336FG, fied as M hereinafter), an ethoxylated, ylated C14-C13 alcohol (available commercially from Nalco, Inc. as Product No. 00PG-007, identified as N hereinafter), nonionic alkoxylated (.2ng alcohol comprising both ethoxy and propoxy groups (available commercially from Nalco, Inc. as Product No. R-50360, identified as O hereinafter), nonionic propylene , ethylene glycol block copolymer (available cially from Nalco, Inc. as Product No. PPlO- 3038, identified as P hereinafter), an ethoxylated C11-C14 alcohol (available commercially from Nalco, Inc. as Product No.PPlO-3l48, identified as Q hereinafter), a propylene oxide glycol polymer (available commercially from Nalco, Inc. as Product No. 7906, identified as R hereinafter), a C16—C18 alcohol able commercially from Nalco, Inc. as Product No.7465, identified as S hereinafter).

Table 30. Percent Foam Height Results* Antifoam 0 mg/L 10 mg/L 100 mg/L 1,000 mg/L 10,000 mg/L (blank) None 69% N 6% O 6% P 15% Q 97% R 52% 19% 10% 0% M 56% 0% 0% 0% S 65% 61 % 19% 13% * Lower % is better result Table 31. Foam Persistence Results* Antifoam 10,000 mg/L N No 0 No P Yes W Yes R No M No S Yes * "No" foam persistence is better result As is shown in Tables 30 and 31, the am agents showing the most advantageous results were M, O, and R. As can be seen by the s, some of the antifoaming agents were not effective at reducing the foaming of the cleaning on.

In particular, the antifoaming agents of M and N were the most effective of the antifoaming agents tested. The environment of cleaning was one of high acid, high conductivity, a high concentration of cleaning solution and an unusual urea tetrafluoroborate nd, as well as other operating conditions in the evaporator of high temperature and presence of contaminant ions.

Example 22: Fields tests Based on very positive lab s for dissolution of deposits obtained from plant evaporators, a full-scale ng of evaporator was conducted. To start cleaning, the system was taken off-line, drained and flushed with utility water. A known volume of utility water was added to the evaporator, and then concentrated cleaning composition was added to provide an approximately 15% v/v tration. Since the evaporator was recently taken off-line, the system was still hot at the start of the cleaning process. Some difficulty was initially tered in keeping the on-line temperature readings of the ng solution below the recommended 80°C limit.

After the initial addition of the cleaning solution, a serious g situation was detected inside evaporator based on wide ?uctuations in water level ements. Foaming is a serious problem that must be avoided and quickly remedied when detected because it can cause safety alarms/switches to activate, it can cause cavitation to occur in recirculating pumps, it can limit recirculation of internal ?uids, it can result in system Vibration, and it can result in fouling of the demister system, which s in contamination of the evaporator distillate and serious uences to the evaporator . The g that occurred was unexpected and was remedied by addition of an antifoam with similar composition to M at a dosage rate of approximately 40 mg/L. Foaming within the evaporator system subsided and it was le to continue with the chemical cleaning process using a 15V/v% composition A cleaning composition.

It was also noted during the cleaning process that the temperature of the cleaning on tended to increase 2-30C/hour based on the pumping energy added to the system in order to continuously recirculate the cleaning solution. In order to provide cooling to the system during the cleaning process, additional amounts of utility water and the cleaning composition were added to the system over a 25 hour period. The noticeable decreases in temperature represent periods when significant amount of cool utility water + fresh cleaning composition were added to the existing cleaning solution.

Subsequent improvements in cleaning procedure have significantly reduced the need to add more utility water to provide cooling to the system.

Progress of ator cleaning process was monitored by analyzing grab samples of cleaning solution from primary and secondary sumps. ICP spectroscopy was used to measure trations of aluminum, calcium, magnesium and silica from deposit dissolution. ICP spectroscopy (chromium and iron) was also used to determine if any significant corrosion was occurring on internal surfaces of ator system during cleaning. The concentration of cleaning composition was ined by a simple titration procedure and additional treatment added to maintain approximately 15% v/v concentration of cleaner, as needed.

Because the volume of cleaning solution increased during the cleaning process, ICP spectroscopy results need to be compensated for changes in system volume, which produces on in concentrations of species being analyzed. A comparison of ICP spectroscopy readings for silica tration (uncorrected versus system volume- corrected) from samples of ng solution is shown in Figure 9.

It is clear that correcting ICP spectroscopy readings for changes in system volume during ator cleaning is very important in properly interpreting the results. The ected analytical results suggest that cleaning was complete after several hours. Using uncorrected ical results could have led to decision to terminate cleaning process before it was complete. In reality, removal of te-based deposits was occurring during entire 25 hour cleaning period. Although most of the silica from deposits was released during first few hours of cleaning, the more tenacious deposits were likely being removed during 5-25 hours of cleaning. Further, the use of volume-corrected results showed about 70% more dissolution of silica-based deposits, as compared to the uncorrected ICP spectroscopy results. Based on the trends above, system—volume corrected results will be used during rest of the discussion.

] System-volume corrected ICP spectroscopy results for aluminum, calcium, and magnesium (refer to Figures 10—12) gave similar trends as the analytical readings for silica.

] The cleaning solution grab samples obtained during the cleaning process were very darkly colored, which indicates high level of organics likely were removed from deposits by the ng composition. Dark-colored substances precipitating from cleaning samples over time were collected and measured by C/H/N analyzer. The analytical s showed about 700 mg/L of organics were present, which indicates the cleaning composition is capable of removing inorganic and organic-based deposits.

In addition to analyzing cleaning solution s to quantify dissolution of inorganic and c deposits, those same samples were also measured for chemical evidence of general corrosion on internal surfaces of evaporator. The largest internal surface area of evaporator being cleaned is AL—6XN® which is a superaustenitic stainless steel alloy composed of 23.5—25.5% nickel, 20-22% chromium, 6-7% molybdenum content, trace elements and remainder of approximately 41-51% iron content heny Technologies Inc., 2014). The evaporator heat-exchanger tube s were manufactured from AL—6XN alloy and had a surface area of approximately 12,000 m3. Inductively coupled plasma (ICP) spectroscopy was used to measure chromium and iron concentrations in the cleaning composition s. Those analyses were combined with information about the evaporator e area, AL-6XN specific gravity and cleaning solution volume in order to estimate general corrosion rate of AL- 6XN. Figure 12 shows the ted general corrosion rate of AL—6XN and the temperature of the cleaning solution ge of primary and secondary readings) during the cleaning process.

The estimated corrosion rate (refer to Figure 13) increases as the temperature of cleaning solution increases, a reasonable response. Maximum general corrosion rate on AL—6XN ted from cleaning ?uid analyses was 1.9 mpy (48 um/yr), which is well below the allowable limit of 50 mpy (1270 [rm/yr) set by the customer. Since use of Cleaning Treatment "A" is typically a 1-2 day process, a ible increase of ~0.005-0.01 mpy (~0.13—0.26 [rm/yr) per cleaning would be added to overall annual ion rate of AL—6XN.

] The 15 v/v% solution of the cleaning composition was able to remove deposits throughout the evaporator and remove deposits that resisted removal by mechanical cleaning with a high-pressure wash.

] Although exceptional results were obtained with the first use of the cleaning composition of the invention, some residual deposits were observed in secondary system of the evaporator during inspection. However, it was noted that any residual deposits after chemical cleaning were much easier to remove by a mechanical cleaning. Further refinements in application of the cleaning composition and multiple ngs over time of the ator system would likely inhibit the formation of tenacious deposits in the wetted portion of the evaporator after chemical cleaning.

Inspections of evaporators which used a 15 v/v% solution of the cleaning composition have shown it is possible to clean down to the bare-metal surface throughout the primary and secondary systems.

After ing 15 v/v% solution of the cleaning composition to remove evaporator deposits, significant volumes of used ng solution (up to 200 m3 or more) may need to be removed before bringing the evaporator back on-line. During initial cleaning of a plant evaporator, used cleaning on was neutralized with caustic and then d by trucking te for disposal. Disposal of used cleaning solution by utilizing on-site systems is red and less costly. Testing was conducted to ensure that used 15 v/v% solution of the cleaning composition would be fully ible with the downstream disposal water treatment system. Testing was also conducted on the caustic neutralization process of used cleaning solution to ensure that optimal pH for disposal was obtained as quickly as possible without generating excessive heat. After the initial application of 15 v/v% solution of the cleaning composition to the plant evaporator, all subsequent cleanings used the on—site disposal water treatment system for disposal of the used, neutralized cleaning composition. This resulted in an easier ng procedure and savings in waste disposal costs.

Example 23: Dissolution of pigging t from once-through steam generator (OTSG) The test method ted of weighing several grams (~3 g) of a OTSG pigging t solid into a 4 oz. c jar. Followed by the addition of 100 mL of distilled water. The test acid was prepared as a 15 wt. % of Composition A in distilled water. The cap to the jar was attached and the jar was shaken vigorously several times to completely wet the solid. If necessary, the cap was loosened to vent the build-up of pressure. The jars were stored in a circulating water bath heated to 750C with an integral shaker. ically, samples (3 mL) were taken at least one hour after shaking. The samples (2 g) were then syringe filtered h a 0.45 it filter, dried, and the percent dissolution was calculated.

Composition Hours Dissolution (%) Water 5 10 A 5 30 A 70.9 31 When introducing elements of the present invention or the preferred ments(s) thereof, the articles "a", "an the" and "said" are intended to mean that there are one or more of the elements. The terms "comprising", "including" and "having" are intended to be inclusive and mean that there may be additional elements other than the listed elements.

] In view of the above, it will be seen that the several objects of the invention are achieved and other advantageous results attained.

As various changes could be made in the above compositions and methods Without departing from the scope of the invention, it is intended that all matter contained in the above ption and shown in the anying drawings shall be interpreted as illustrative and not in a limiting sense.

Claims (14)

WHAT IS CLAIMED IS:

1. A method for increasing recovery of crude oil from a subterranean hydrocarbon - containing formation, the method comprising: injecting an acid composition comprising a salt of a nitrogen base having a fluoroinorganic anion into a well which is in contact with the subterranean hydrocarbon-containing formation, thereby increasing recovery of crude oil, wherein the nitrogen base is urea, biuret, an alkyl urea, an alkanolamine, an alkylamine, a dialkylamine, a trialkylamine, an alkyldiamine, an alkyltriamine, an alkyltetramine, a polyamine, an acrylamide, a polyacrylamide, a vinyl pyrollidone, a polyvinyl pyrollidone, or a combination thereof and the fluoro-inorganic anion is a borate or a phosphate anion.

2. The method of claim 1 , wherein the acid composition is diverted toward a zone of the subterranean hydrocarbon-containing formation that has a lower permeability to fluid than an adjacent zone.

3. The method of claim 1 or 2, wherein the ranean hydrocarbon-containing ion ses a sandstone reservoir or a carbonate reservoir.

4. The method of claim 3, wherein the subterranean hydrocarbon-containing ion comprises a carbonate reservoir.

5. A method for removing an inorganic or organic deposit by contacting an acid ition with an al e of a well, the surface being in t with a liquid containing deposit-forming species, wherein the acid on comprises a salt of a nitrogen base having a fluoro-inorganic anion and the nitrogen base is urea, biuret, an alkyl urea, an alkanolamine, an alkylamine, a dialkylamine, a trialkylamine, an alkyldiamine, an riamine, an alkyltetramine, a polyamine, an acrylamide, a polyacrylamide, a vinyl pyrollidone, a polyvinyl pyrollidone, or a combination thereof and the fluoro-inorganic anion is a borate or a phosphate anion.

6. The method of claim 5 , wherein the well is an oil well, a geothermal well, a disposal well, or a reinjection well.

7. The method of claim 5 or 6, n the deposit is a metal oxalate, a metal ate, a silicate, a metal sulfate, or a combination thereof.

8. The method of claim 7, wherein the deposit is silicate.

9. The method of any one of claims 1 to 8, wherein the fluoro-inorganic anion is luoroborate, hexafluorophosphate, or a combination thereof.

10. The method of claim 9 , wherein the -inorganic anion comprises tetrafluoroborate.

11. The method of any one of claims 1 to 10, wherein the nitrogen base comprises urea.

12. The method of any one of claims 1 to 1 1, wherein the fluoro-inorganic anion comprises tetrafluoroborate and the nitrogen base comprises urea and the molar ratio of urea to tetrafluroboric acid used to prepare the salt is 1:3 to 3:1.

13. The method of any one of claims 1 to 1 2, wherein the acid composition further comprises a surfactant, and the surfactant is a nonionic surfactant.

14. The method of any one of claims 1 to 13 wherein the concentration of the acid ition is from about 5 wt.% to about 30 wt.% based on the total weight of the aqueous mixture injected. magma; u ”a if; mwilmli «in? §x§§§w in?mwmwa? gm» ma?a 4%,? Qm Ex 3&3 m5 ?ggm Qw. 2‘13 8:23 82:33 8221582} “1;.” ?g saga“:W W0 201