MX2022013377A

Fluro-inorganics for inhibiting or removing silica or metal silicate deposits.

Abstract

The present invention generally relates to methods for removing and inhibiting deposits, reducing the pH of aqueous mixtures and increasing the recovery of crude oil from underground 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.

MX2022013377A, drawing sheet 1 — Sheet 1 of 15

Term

10.4 yearsleft in the term

Expires 23 February 2037.

10 claims: 6 independent, 4 dependent

1
CLAIMS REIVINDICACIONES 1. A method of removing an organic or inorganic 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 fluoro-inorganic anion and 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 pyrrolidone, a polyvinyl pyrrolidone, or a combination thereof. 1. Un método para remover un depósito orgánico o inorgánico al poner en contacto una composición de ácido con una superficie interna de un pozo, estando la superficie en contacto con un líquido que contiene especies formadoras de depósito, en donde la solución de ácido comprende una sal de una base de nitrógeno que tiene un anión fluoro-inorgánico y la base de nitrógeno es urea, biuret, una alquil urea, una alcanolamina, una alquilamina, una dialquilamina, una trialquilamina, una alquildiamina, una alquiltriamina, una alquiltetramina, una poliamina, una acrilamida, una poliacrilamida, un vinil pirrolidona, una polivinil pirrolidona, o una combinación de los mismos.
6
The method according to any of claims 1 to 5, wherein the nitrogen base comprises urea. 6. El método de acuerdo con cualquiera de las reivindicaciones 1 a 5, en donde la base de nitrógeno comprende urea.
7
The method according to any of claims 1 to 6, wherein the fluoro-inorganic anion comprises tetrafluoroborate and the nitrogen base comprises urea and the molar ratio of urea to tetrafluoroboric acid used to prepare the salt is 1:3 to 3 :1. 7. El método de acuerdo con cualquiera de las reivindicaciones 1 a 6, en donde el anión fluoro-inorgánico comprende tetrafluoroborato y la base de nitrógeno comprende urea y la relación molar de urea a ácido tetrafluorobórico usado para preparar la sal es de 1:3 a 3:1.
8
The method according to any of claims 1 to 7, wherein the acid composition further comprises a surfactant, and the surfactant is a nonionic surfactant. 8. El método de acuerdo con cualquiera de las reivindicaciones 1 a 7, en donde la composición de ácido comprende además un tensoactivo, y el tensoactivo es un tensoactivo no iónico.
9
The method according to any of claims 1 to 8, wherein the deposit is a metal oxalate, a metal carbonate, a silicate, a metal sulfate or a combination thereof. 9. El método de acuerdo con cualquiera de las reivindicaciones 1 a 8, en donde el depósito es un oxalato de metal, un carbonato de metal, un silicato, un sulfato de metal o una combinación de los mismos.
10
The method according to any of claims 1 to 9, wherein the concentration of the acid composition is from about 5% by weight to about 30% by weight based on the total weight of an injected aqueous mixture. 10. El método de acuerdo con cualquiera de las reivindicaciones 1 a 9, en donde la concentración de la composición de ácido es de aproximadamente 5% en peso a aproximadamente 30% en peso basado en el peso total de una mezcla acuosa inyectada.

Independent claims6

550 paragraphs in 6 sections, as filed

ORGANIC FLUORO-1N TO INHIBIT OR REMOVE SILICA OR METAL SILICATE DEPOSITS

FIELD OF THE INVENTION

The present invention relates generally to methods for inhibiting and/or removing deposits, reducing the pH of an aqueous liquid, and increasing oil production from an underground formation, the methods comprising contacting a composition with a surface in contact with a liquid, wherein the composition comprises a salt of a nitrogen base with a fluoroinorganic anion. In particular, these methods of removing deposits and reducing pH can be used in steam generators, evaporators, heat exchangers, and the like that use water compositions 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., removal of inorganic and organic scales, decarbonization, pH adjustment, general cleaning and disinfection; However, these acids can be extremely hazardous to handle and transport, highly corrosive to metal surfaces, and can lead to mineral scaling.

Traditionally, mineral acids such as hydrochloric acid or inhibited hydrochloric acid are used to acidify or neutralize highly alkaline water systems. The use of mineral acids can cause corrosion problems for pipes and other equipment. Mineral acids can also cause metal loss during cleaning of dirty aqueous systems with deposits and scale in systems contacting the aqueous mixture; The system may be heat exchangers, a cooling or heating system, a pipeline, a water distribution system, or an oil or geothermal well. Some waters that may have very high alkalinity must be neutralized before use in order to avoid deposition. Such waters neutralized with mineral acids will subsequently become very corrosive and cause metal loss due to the presence of counterions from the neutralization of mineral acids.

Silicate-based deposits can occur in many industrial systems. 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 operation/maintenance costs, and in some cases, lead to equipment failure. Steam generators and evaporators are especially prone to silicate deposits due to operation at elevated temperatures, pH, and increased cycles of concentration (COC).

Chemical treatment programs can be used to minimize deposits, but the entire system described above can become dirty over time and cleaning is in order. Options for cleaning are chemical or mechanical in situ programs.

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

A reduction in permeability is typically due to the entry of fine particles through the flow of oil into the production well. Around this well, these particles gradually accumulate, plugging the natural pores in the rock. Oil may then no longer flow at an efficient rate through this well. These particles can be of various origins (for example, 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 fluid 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 fluid. Therefore, this well stimulation method can cause these particles and rock to partially dissolve, and make the formation rock more porous, thereby increasing the mobility of oil in the formation and increasing well production.

Thus, there is a need to develop safe acids to perform many functions within the petroleum industry, i.e., removal of inorganic and organic scales, decarbonization, pH adjustment, general cleaning and disinfection, which are safer for handling and transportation. than conventional acids.

BRIEF DESCRIPTION OF THE INVENTION

One aspect of the invention is a method of removing silica or silicate deposits or inhibiting the deposition of silica or silicate comprising contacting a cleaning composition with a surface. The surface is in contact with a liquid that contains a silica or silicate and that has a silica or silicate deposit or is susceptible to the formation of a silica or silicate deposit. The cleaning composition comprises an antifoam agent and a salt of a nitrogen base with a fluoro-inorganic anion.

Another aspect of the invention is a method of reducing the pH of an aqueous system by contacting the surface of a piece of equipment with an acid composition, wherein the acid composition comprises a salt of a nitrogen base having a fluoro-inorganic anion.

Another aspect is a method of reducing the pH of an aqueous system comprising contacting an acid composition with an aqueous mixture that contacts the internal surface of a piece of equipment. The acid composition may consist of a salt of a nitrogen base with a fluoro-inorganic anion.

A further aspect of the invention is a method for increasing the recovery of crude oil from a subsurface hydrocarbon-containing formation, the method comprising injecting an acid composition comprising a salt of a nitrogen base with a fluoro-inorganic anion into a well that is in contact with the underground hydrocarbon-bearing formation.

Yet another aspect of the invention is a method of removing an organic or inorganic 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 with a fluoro-inorganic anion.

BRIEF DESCRIPTION OF THE DRAWINGS

Figure 1 is a graph of average NCM against pH of various compositions A, D and F with I inhibited.

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

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Figure 3 is a schematic view of the dynamic laboratory testing apparatus.

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

Figures 5A and 5B are images of a dirty distributor cap and the same distributor cap cleaned with the cleaning composition, respectively.

Figure 6 is a graph of % dissolution of a reservoir against % v/v cleaning composition concentration tested in a laboratory scale experiment described in Example 18.

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

Figure 8 is a plot of the amount of silica, calcium and aluminum removed in mg/L against 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 the silica concentration (in mg/L) removed versus time using a cleaning composition where the silica concentration is the corrected and uncorrected volume for the addition of fluid to the system tested in an experiment. field described in Example 22.

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

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

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

Figure 13 is a graph of corrosion rate (in average mpy) against time using a cleaning composition tested in a field experiment described in Example 22.

Corresponding reference characters indicate corresponding parts throughout the drawings.

DESCRIPTION OF PREFERRED MODALITIES

The present invention is directed to methods for removing silica or silicate deposits. The cleaning compositions of the invention provide more effective cleaning of tanks, faster wait time for equipment, and reduce the need to mechanically clean affected surfaces of the industrial system. Additionally, the cleaning compositions are less hazardous than many alternative cleaning agents. Furthermore, the cleaning compositions are particularly effective in 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 flow, etc.).

One aspect of the present invention is directed to reducing the pH of an aqueous system comprising contacting an acid composition with an internal surface of a piece of equipment or contacting an acid composition with an aqueous mixture that contacts with an internal surface of a piece of equipment wherein the acid composition comprises a salt of a nitrogen base with a fluoro-inorganic anion. These methods offer reduced corrosion of metal surfaces, less loss of metal atoms, and reduce the need to mechanically clean affected system surfaces. Additionally, the compositions are less hazardous than many alternative acids for lowering pH in aqueous systems. Additionally, the compositions are particularly effective in preventing carbonate, oxalate, phosphate, iron, manganese, sulfate and/or silica based scale in equipment, including pipes, tanks, steam generators, heat and cooling exchangers and evaporators.

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 recirculation process, produced water is passed through cooling towers and evaporators where high quality feedwater is produced. Alkalinity and counterions, i.e. Ca, for carbonates and sulfates, also concentrate other scale-forming ions as well as corrosive ions such as chlorides, which are prone to scale formation and cause corrosion. Traditionally, acids are used to neutralize that alkalinity but this is done at the risk of exposing the surfaces to acids that are known to be corrosive for their virtues, as well as the addition of more corrosive ions such as chlorides and sulfates. By using the present invention, alkalinity can be neutralized, CO2 can be released and the risk of corrosion is decreased.

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

This method of removing heavy crude oil trapped in carbonate fields by injecting an acid composition generates carbon dioxide that helps lift the oil through the well. This treatment can also rejuvenate geothermal production and injection wells by contacting the well with an acid composition comprising a salt of a nitrogen base having a fluoro-inorganic anion that removes various deposits and increases steam production and electricity.

Additionally, in sandstone or sandstone formations, the methods described here can restore or improve natural formation permeability around the wellbore by removing formation damage, dissolving pore-clogging material, or by enlarging pore spaces. . Traditionally, this method involves the use of a solution generally composed of a hydrochloric acid predischarge, a main treatment fluid (HCl and HF mixture), and an overload (weak acid solution or brine). The treatment fluid is kept under pressure within the reservoir for a period of time, after which the well is cleaned and returned to production. Using the composition of this invention, the use of HCl and HF, which are known as corrosive acids, has been eliminated.

Additionally, in carbonate formations, the methods described here can create new highly conductive channels (tubular cavities due to trapped gases) that prevent damage.

These methods can be used for water flooding for carbonate fields. During this process, the formations produce water high in carbonate ions, which can interact with flaking cations such as calcium, magnesium, strontium, and barium to form thick flakes. Treating produced water with an acid can form carbon dioxide and limit scale formation. However, conventionally used acids are corrosive in nature and can cause corrosion problems in downstream unit operations. The methods described here can be used to release carbon dioxide without the corrosive side effect of downstream processing operations that conventional acids can exhibit.

A further aspect of the invention is a method for acid well drilling treatments; Treatment can help remove scale or other similar deposits from drilling and completion components. Conventionally, inhibited acids are used to reduce the rate of corrosion; however, the corrosion rate may still be unacceptable. The methods described here can remove scale and similar deposits while exhibiting less corrosion than conventional acids, thereby protecting the well. As detailed above, these methods can rejuvenate geothermal and production wells.

A further aspect of the present invention is directed to a method of removing silica or silicate deposits comprising contacting a cleaning composition with a surface, the surface having or being susceptible to the formation of silica or silicate deposits from contact with a liquid containing silica or silicate, wherein the cleaning composition comprises a salt of a nitrogen base with a fluoro-inorganic anion. The cleaning composition may further comprise an antifoam agent.

The compositions of the present invention may be provided together with a fluid or an aqueous medium and may be provided in a ready-to-use form or may be provided as stand-alone agents and the composition may be prepared at the treatment site. Depending on the nature of the use and application, the composition may be in the form of a concentrate containing a higher proportion of nitrogen base salt having a fluoro-inorganic anion, the concentrate is diluted with water or other solvent or liquid medium. or other components such as antifoam agent, organic silica or silicate deposit inhibitor, corrosion inhibitor, or surfactant before or during use. Such concentrates can be formulated to withstand storage for long periods and are then diluted with water to form preparations that remain homogeneous for a sufficient time so that they can be applied by conventional methods. After dilution, these preparations may contain varying amounts of the acid composition or cleaning composition, depending on the intended purpose or end-use application.

The acid composition or cleaning composition may comprise a salt of a nitrogen base with a fluoroinorganic anion.

The fluoro-inorganic anion may comprise a borate ion, a phosphate ion or a combination thereof. Preferably, the fluoro-inorganic anion comprises a borate ion.

The fluoro-inorganic anion may comprise tetrafluoroborate, hexafluorophosphate or a combination thereof. In addition, a hydrolysis product of tetrafluoroborate and hexafluorophosphate comprising fluorine atoms can also be used.

Preferably, the fluoro-inorganic anion of the acid composition or cleaning composition comprises tetrafluoroborate.

The acid composition or cleaning composition may further comprise water.

The acid composition or cleaning composition may have the fluoro-inorganic anion comprising tetrafluoroborate and the base the nitrogen comprising urea and the molar ratio of urea to tetrafluoroboric acid used to prepare the salt is from 1:3 to 5:1 , preferably from 1:2 to 3:1. The nitrogen base (e.g., urea) can react with the inorganic fluoro-acid (e.g., fluoroboric acid) to form the salt of a nitrogen base with a fluoro-inorganic anion (e.g., u tetrafluoroborate). ). However, the relative amounts and/or concentrations of the inorganic fluoroacid component and base component in the compositions of the present invention can vary widely, depending on the desired function of the composition and/or the cleaning activity required. As such, the weight ratios and/or concentrations used can be selected to achieve a composition and/or system having the desired cleanliness and safety and health characteristics.

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

The salt of a nitrogen base having a fluoroinorganic anion is described in US Patent Nos. 8,389,453 and 8,796,195 and commercially available from Nalco-Champion as Product No. EC6697A.

The methods for increasing the recovery of crude oil from an underground hydrocarbon-bearing formation described herein may have the acid composition diverted to an area of the underground hydrocarbon-bearing formation that has a lower fluid permeability than an adjacent area.

The underground hydrocarbon-bearing formation may comprise a sandstone rock deposit or a carbonate deposit.

The underground hydrocarbon-bearing formation may comprise a carbonate deposit.

The methods described here can be used in a well that is an oil well, a geothermal reservoir, a disposal well, and a reinjection well.

The internal surface in contact with the acid composition or cleaning composition may 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 here could also be a pipe, drain line, or fluid transfer line.

Preferably, the piece of equipment cleaned by the methods described herein is an evaporator 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 may be a steam-assisted gravity drainage system, a steam flooding system, or a cyclic steam stimulation system.

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

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

The acid composition or cleaning composition can be used in addition to a pigging pipe cleaning process. The pipe pigging process can be used on a tube bundle, pipeline, drain line or fluid transfer line where deposits have formed and partially blocked the flow of fluid through the line. The pigging pipe cleaning process involves placing a device (i.e., the pig) that is approximately the same diameter as the internal diameter of the line or pipe to be cleaned and launching the pig through the line or pipe, usually applying pressure behind the scraper. The acid composition or cleaning composition may assist in the pigging process by removing or softening deposits formed in lines where less pressure is needed to propel the pig through the line or pipe and removal. of deposits increases.

The aqueous system may be produced water, surface water, groundwater, feed water, or a combination thereof.

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

The acid composition or cleaning composition can reduce corrosion of the internal surface of the equipment part compared to the same method with a conventional acid composition (for example, hydrochloric acid, hydrofluoric acid, sulfuric acid, etc.) .

The acid composition or cleaning composition can reduce the loss of metal from the inner surface of the piece of equipment compared to the same method using a conventional acid composition (for example, hydrochloric acid, hydrofluoric acid, sulfuric acid, etc.).

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

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

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

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

The chelating agent may be ethylenediaminetetraacetic acid (EDTA), hydroxyethane 1-1,1-diphosphonic acid (HEDP), gluconate or a combination thereof.

Methods for removing an organic or inorganic deposit in a well may remove deposits of metal oxalate, metal carbonate, silicate, metal sulfate, or a combination thereof.

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

The concentration of the net acid composition may be from about 5% by weight to about 85% by weight.

To remove deposits in wells, the concentration of the acid composition in the injection mixture can be from about 5% by weight to about 30% by weight. Preferably, the concentration of the acid composition is about 15% by weight based on the total weight of the carrier fluid (e.g., aqueous mixture) that is emptied into a well. After 24 to 36 hours of contact of the aqueous mixture with the wellbore and formation, the mixture is then pumped out of the wellbore or formation.

The method of cleaning the surface in contact with a liquid containing silica or silicates can be carried out at a temperature of about 0°C to about 374°C, about 20°C to about 320°C, or about occur during hydraulic fracturing of the well.

The antifoam agent of the cleaning composition may comprise a nonionic silicone (commercially available from Nalco, Inc. as Product No. 336FG), a propoxylated, ethoxylated C14-C18 alcohol (commercially available from Nalco, Inc. as Product No. 00PG-007), alkoxylated nonionic CeCium alcohol comprising both ethoxy and propoxy groups (commercially available from Nalco, Inc. as Product No. R-50360), nonionic propylene glycol, ethylene glycol block copolymer (commercially available from Nalco, Inc. as Product No. PP10-3038), an ethoxylated C11-C14 alcohol (commercially available from Nalco, Inc. as product No.PPI0-3148), a propylene glycol oxide polymer (commercially available from Nalco, Inc. as Product No. 7906), a C16-C18 alcohol (commercially available from Nalco, Inc. as Product No.7465) or a combination of them.

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

The antifoam agent may be present in the cleaning composition at a concentration of about

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The antifoam agent is effective at low pH and very high conductivity of cleaning compositions, as well as in cleaning solutions containing hardness, silica, organic or heavy metal ions (e.g., iron) extracted from dirty surfaces.

The acid composition or cleaning composition may also include a corrosion inhibitor. The corrosion inhibitor employed in the present invention may be one or more corrosion inhibitors known to those skilled in the art and/or specifically dictated by various factors including, but not limited to, the type of surface to be treated (metals, such as aluminum, steel, iron, brass, copper, ceramic, plastic, glass, etc.), the concentrations of tetrafluoroboric acid included in the system, the pH of the system, the efficiency of the inhibitor, solubility characteristics of the inhibitor, desired length of exposure of the system to the surface, environmental factors, etc. Accordingly, said corrosion inhibitor may be a sulfonate, a carboxylate, an amine, an amide, a borate-based inhibitor compound or a combination thereof.

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

Corrosion inhibitors suitable for inclusion in the compositions include, but are not limited to, quaternary alkyl, hydroxyalkyl, alkylaryl, arylalkyl or arylamine salts; mono- or polycyclic aromatic amine salts; imidazoline derivatives; mono-, di- or trialkyl or alkylaryl phosphate esters; hydroxylamine phosphate esters; phosphate esters of polyols; and monomeric or oligomeric fatty acids.

Alkyl, hydroxyalkyl, alkylaryl, arylalkyl or arylamine quaternary salts include those alkylaryl, arylalkyl and arylamine quaternary salts of the formula [N+ R5aR6aR7aR8a][X] where R5a, R.6a, R.7a and R.8a contain one of 18 carbon atoms, and X is Cl, Br or I. In certain embodiments, R5a, R.6a, R.7a and R.8aeach is independently selected from the group consisting of alkyl (e.g., Ci-Cis alkyl), hydroxyalkyl (e.g., Ci-Cis hydroxyalkyl), and arylalkyl (e.g., benzyl). The mono- or polycyclic aromatic amine salt with an alkyl or alkylaryl halide include salts of the formula [N+ R5aR6aR7aR8a][X ] where R5a, R.6a, R.7a and R.8a They contain one of 18 carbon atoms, and X is Cl, Br or I.

Suitable quaternary ammonium salts include, but are not limited to, tetramethylammonium chloride, tetraethylammonium chloride, tetrapropylammonium chloride, tetrabutylammonium chloride, tetrahexylammonium chloride, tetraoctylammonium chloride, benzyltrimethylammonium chloride, benzyltriethylammonium chloride, phenyltrimethylammonium chloride, phenyl 11ri et i I ammonium chloride, cetylbenzyldimethylammonium chloride, hexadecyltrimethylammonium chloride, quaternary dimethyl alkyl benzylammonium compounds, quaternary monomethyl dialkyl benzylammonium compounds, quaternary trimethyl benzylammonium compounds, and quaternary trialkyl benzylammonium compounds, wherein the alkyl group may contain between about 6 and about 24 carbon atoms, about 10 and about 18 atoms carbon, 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 ammonium salt is a quaternary ammonium salt of benzyl alkylamine, a quaternary ammonium salt of benzyl triethanolamine, or a quaternary ammonium salt of benzyl dimethylaminoethanolamine.

The corrosion inhibitor may be a quaternary ammonium or a quaternary alkyl-pyridinium salt, such as those represented by the general formula:

R9aB where R9a 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 I. Among these compounds are alkyl-pyridinium salts and benzyl quats a I qui I - pyridini o. Illustrative compounds include m eti I-pyridinium chloride, eth i I - pyridinium chloride, propi I - pyridinium chloride, buti I - pyridinium chloride, octyl-pyridinium chloride, decylpyridinium, I auri I - pyridinium chloride, cet I I - pyridinium chloride, benzy I - pyridinium chloride and a I qui I - benci I - pyridinium chloride, preferably wherein the alkyl is a Ci-Ce hydrocarbyl group. In certain embodiments, the corrosion inhibitor includes benzyl iridine chloride.

The corrosion inhibitor may also be an imidazoline derived from a diamine, such as ethylenediamine (EDA), diethylenetriamine (DETA), triethylenetetraamine (TETA), etc. and a long chain fatty acid such as TALL oil fatty acid (TOFA). Suitable imidazolines include those of the formula:

ινΐΛ/a/zuzz/u 1 óói i

where R12a and R.13a are independently an alkyl group of CiCe or hydrogen, R11a is hydrogen, alkyl of Ci-Ce, hydroxyl alkyl of Ci-Ce or arylalkyl of Ci-Ce and R10a is a C1-C20 alkyl group or a C1-C20 alkoxyalkyl group. Preferably, R11a, R.12a and R.13a They are each hydrogen and R10a It is the typical mixture of alkyl in TALL fatty acid (TOFA).

The corrosion inhibitor compound may also be a midazolinium compound of the following formula:

R11ap12a /

T+)>-R10a pISa^N

R14 to where R12a and R.13a are independently a C1Οθ alkyl group or hydrogen, R11a and R.14 to are independently hydrogen, Ci-Ce alkyl, hydroxy Ci-Ce alkyl or Ci-Ce arylalkyl and R10 is a C1-C20 alkyl or a C1-C20 alkoxyalkyl group.

Suitable mono-, di- and trialkyl, as well as alkylaryl phosphate esters and mono-, di- and triethanolamine phosphate esters typically contain between 1 to about 18 carbon atoms. Mono-, di-, and trialkyl phosphate esters, or alkylaryl or arylalkyl phosphate esters, are those prepared by reacting a C3-C18 aliphatic alcohol with phosphorus pentoxide. The phosphate intermediate exchanges its ester groups with triethyl phosphate with triethyl Iphosphate producing a broader distribution of alkyl phosphate esters. Alternatively, the phosphate ester can be made by mixing with an alkyl diester, a mixture of low molecular weight alkyl alcohols or diols. Low molecular weight alkyl alcohols or diols preferably include Ce to C10 alcohols or diols. Furthermore, phosphate esters of polyols and their salts containing one or more 2-hydroxyethyl groups and hydroxylamine phosphate esters obtained by reacting polyphosphoric acid or phosphorus pentoxide with hydroxylamines such as diethanolamine or triethanolamine are preferred.

The corrosion inhibitor compound may also 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 those fatty acids.

The acid composition or cleaning composition may also comprise scale inhibitor.

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

The acid composition or cleaning compositions may optionally include one or more nonionic, anionic, cationic or amphoteric surfactants or a mixture of these to improve both performance and economy. The type of surfactant selected may vary, for example, depending on the nature of the particular conditions of use (for example, type of residue to be removed or type of surface), and/or the nature of the solvent (for example, solvent aqueous versus a less polar one such as an alcohol or other organic solvent).

Preferably, the cleaning composition may include a nonionic surfactant. The nonionic surfactant may be Videt Q3™ surfactant, which demonstrates rapid wetting due to the associated excellent dynamic surface tension profile and is commercially available from Vitech International, Inc.).

The cleaning composition may further comprise an organic silica or silicate deposition inhibitor.

The inorganic or organic silica or silicate deposition inhibitor may be boric acid, borates, oligomeric and polymeric compounds (for example, polyethylene glycol monomethacrylate acrylic acid copolymer (Product No. 3DT155 available from Nalco) and 2-propenic acid, polymer with a 2-propenyl-wh id rox i po I i (ox i -1,2-ethanediyl), sodium salt (Product No. 3DT156 available from Nalco).

The compositions of the present invention may be provided together with a fluid or aqueous medium and may be provided in a ready-to-use form or may be provided as separate agents and the composition may be prepared at the site of treatment. Depending on the nature of the use and application, the composition may be in the form of a concentrate containing a greater proportion of the salt of a nitrogen base having a fluoro-inorganic anion, the concentrate being diluted with water or other solvent or liquid medium or other components such as antifoam agent, organic silica or silicate deposit inhibitor, corrosion inhibitor or surfactant before or during use. Such concentrates can be formulated to withstand storage for long periods and are then diluted with water to form preparations that remain homogeneous for a sufficient time so that they can be applied by conventional methods. After dilution, these preparations may contain varying amounts of the cleaning composition, depending on the intended purpose or end-use application.

The piece of equipment whose internal surface is cleaned by the method described here could also be a pipeline, drain line, fluid transfer line, production well, or underground reservoir containing hydrocarbon.

The method of cleaning the surface in contact with a liquid containing silica or silicates can be carried out at a temperature of about 0°C to about 374°C, about 20°C to about 320°C or about 40 °C to approximately 100°C.

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

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

The method of removing a silica or silicate deposit can also remove organic deposits. Organic deposits that can be removed from the surface can be water-soluble organic compounds, bitumen, naphthenic acids and organic compounds that can be partially and thermally degraded.

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

When the equipment is online, the acid composition is about 65 to about 85% of the concentration of active acid in the acid composition and about 10 to about 100 ppm of active acid based on volume is fed to the system. of the aqueous system. Additionally, it can be added to other aqueous systems with a chemical feed pump. When the piece of equipment is offline, the acid composition comprises about 10% by weight to about 20% by weight of acid, preferably about 15% by weight of acid in an aqueous mixture and is added to the line. power supply to come into direct contact with the internal surface of the equipment to be cleaned.

Furthermore, when the system is offline for cleaning, the method of cleaning the surface in contact with a liquid containing silica or silicates can be carried out using a cleaning composition having a concentration of about 1% v/v to about 50% v/v, about 3% v/v to about 25% v/v, about 10% v/v to about 20 v/v, or about 15% v/v% of Product No. EC6697A (available from Nalco-Champion) based on the total weight of the acid composition or cleaning composition.

Furthermore, when the system is online and a cleaning process using the acid composition or the cleaning composition is used, the concentration of the cleaning composition in the feed water is from about 5 mg/L to about 300 mg/L. 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 online and a cleaning process using the acid composition or the cleaning composition, the concentration of the acid composition or the cleaning composition in the feed water is from about 30 mg/L to about 100 mg/L.

In particular, the application site for the use of the acid composition or the cleaning composition may be four two-stage evaporators running in parallel. Evaporators work based on the MVC principle. The primary and secondary stages of each evaporator operate in series and are housed in the same containment vessel. One evaporator may be larger than the other three evaporators.

Figure 2 shows the main components in an evaporator system. A vapor compression evaporator (or brine concentrator) 10 may contain various internal structures, including tube packs and brine distributors. The vapor compression evaporator 10 is connected to a compressor 20, a recirculation pump 30, a degasser 60 having a vent 62 and a distillate pump 40. The waste water 52 is fed through a heat exchanger 50 to the degasser 60 and to the vapor compression evaporator 10. The distillate 42 exits the vapor compression evaporator 10 into a distillate pump 40 and through the distillate exchanger. heat 50. The brine is recirculated through the recirculation pump 30 and the residual brine leaves the residual brine line 32. The vapor is compressed by circulating through the compressor 20.

Typical operating characteristics for an evaporator system such as that shown in Figure 2 are detailed in Table 1.

Table 1 - Typical operating characteristics (approx.)

<td>Parameter</td><td>Smaller system</td><td>Larger system</td>

<td>Feed water flow (m3/hr)</td><td> 250</td><td> 300</td>

<td>Tube package surface (m2)</td><td> 12,000</td><td> 12,000</td>

<td>Temp. feed water (°C)</td><td> 80</td><td> 80</td>

<td>Total distillate (m3/hr)</td><td> 244-245</td><td> 293-294</td>

<td>Purge speed (m3/hr)</td><td> ~5-6</td><td> ~6-7</td>

<td>Total concentration cycles (target)</td><td> 45-55</td><td> 45-55</td>

MVC falling film evaporators have high heat transfer characteristics and efficiency compared to other evaporator designs (Heins, W. (2008). Technical Advancements in SAGD Evaporative Produced Water Treatment,

International Water Conference in San Antonio, Texas, October 2630, IWC-08-55). A high heat transfer coefficient is necessary to effectively evaporate water and increase the temperature (ΔΤ ~27°C at the application site) to produce high quality feedwater. Along with the evaporation process, the concentration of substances present in the feed water can be cycled as high as 45-55 times their initial concentration. The combination of high temperature and high concentrations of inorganic and organic substances increases the probability that inversely soluble and particulate substances will deposit in wet portions of the evaporator system.

Therefore, clean heat transfer surfaces are highly desirable for efficient distillate energy production from water containing high levels of inorganic salts and organic contaminants. When deposits form insulating layers on the surfaces of evaporator heat exchangers, a reduction in U values (heat transfer coefficient) occurs. While evaporator operating conditions can be adjusted within certain limits to compensate for decreasing U values, low U values sometime lead to reduced distillate flow rate and reduced evaporator operating speed. In case of insufficient distillate available for plant operation (feedwater for OTSGs and heat recovery steam generators (HRSGs)), then bitumen production can be reduced.

In addition to reducing the heat transfer efficiency of the evaporator and the corresponding distillate production, deposits can clog heat transfer tubes, distribution plates and flow channels. System blockages can lead to poor water distribution, further reduction in distillate production and make system cleaning, even with mechanical means, very difficult, expensive, laborious 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 relationships of various water streams and their chemical compositions can vary considerably over time. Furthermore, the direction to maximize water use efficiency and reduce water discharge through the increased level of water recirculation can lead to increased levels of deposit-forming ions and substances over time. This is enough to prevent the evaporator from operating.

The average evaporator feedwater quality over five months of operation and the impact of operation on the total 45 concentration cycles is shown in Table 2. The inorganic portion of the water chemistry was measured through plasma spectroscopy. inductively coupled (ICP).

Table 2 - Evaporator Feed Water Quality

Impact of Concentration Cycles

<td></td><td colspan="2">Concentration (mg/L)</td>

<td>Chemistry*</td><td>Feeding water</td><td>@ 45 cycles**</td>

<td>Aluminum (as Al)</td><td> 0.23</td><td> 10.4</td>

<td>Calcium (as Ca)</td><td> 2.24</td><td> 101</td>

<td>Magnesium (as Mg)</td><td> 0.58</td><td> 26.1</td>

<td>Hardness Ca + Mg (as CaCO3)</td><td> 8.0</td><td> 360</td>

<td>As silica (as SiOs)</td><td> 244</td><td>It is 10,980</td>

* Additional ions at high concentrations in the feed water are boron ~29 mg/l, Na+ -690 mg/L, 01' -210 mg/L, sulfate and -280 mg/L ** 100% transport is assumed, deposit formation will result in low concentrations measured in the evaporator purge.

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

Due to water recirculation and the need to maximize water use, the levels of deposit-forming inorganic and organic ions in feed water increased over time.

When you use hydroflushing to remove internal deposits, the evaporator system is taken offline and cooled and the internal watery fluid is drained. An entry hatch opens and hydrowashing personnel/equipment enter the evaporator system. When using a high-pressure water wash (hydrowash) lancet, high-pressure water is used to remove deposits and clean internal surfaces. Deposits removed from internal surfaces are collected and carried out of the system for disposal. A long high-pressure water lancet is used to remove deposits from the interior (e.g., tube side) of long tubes in the heat exchanger portion (or tube package) of the evaporator. After the evaporator is cleaned, the system inlet port is sealed and feedwater is added until a normal operating level is reached within the system. Recirculation water pumps are started and steam is normally added to the shell side of the heat exchanger to heat the recirculation water. The mechanical vapor compression pump is started and the system is brought back online.

For the method described here, the evaporator system is taken offline, drained of internal aqueous fluids and allowed to partially cool to an operating range of 0°C to 60°C, preferably, 40°C to 60°C. . A distillate or relatively clean water (e.g. service water) is used to flush the system by partially refilling the evaporator system. Water pumps are used to recirculate rinse water within the evaporator to help remove residual amounts of water that may contain high levels of deposit-forming substances (e.g., silica, hardness ions, aluminum, iron, etc. ). The water recirculation pumps are stopped and the rinse water is drained from the evaporator. The system is then partially filled with distillate or relatively clean water and circulated using recirculating water pumps. A sample of the recirculating water is chemically tested to ensure that any applicable water quality guidelines are met. The temperature of the recirculating water is measured to ensure that it is at the operating stage.

The volume of water in the evaporator system is measured using a water level monitor to determine how much concentrated cleaning solution must be added to achieve the desired concentration of acid composition or cleaning solution (for example, if the volume of water inside of the evaporator is 85 m3, then 15 m3 of concentrated cleaning solution would normally be added to produce a 15% v/v concentration of acid composition or cleaning solution). Also, optionally, an antifoam agent is added to ensure that foaming within the evaporator is reduced to a minimum (e.g. 4 liters of antifoam product in 100 m3 or 100,000 liters of 15% v/v cleaning solution would produce approximately 40 mg/L concentration of antifoam product). Based on past experience, more or less an antifoam can be added to the cleaning solution. Additional antifoam may be injected into the cleaning solution if an unacceptable level of foam persists. The concentration of the acid composition or cleaning solution is verified using an acidity titration method to ensure that the target level of cleaning solution is maintained. If the concentration of acid composition or cleaning solution is too high, then additional water can be added to the evaporator system. If the concentration of the acid composition or cleaning solution is too low, then additional concentrated acid composition or cleaning solution may be added. Samples of acid composition or recirculating cleaning solution are taken at prescribed intervals and the water chemistry is measured by colorimetric analysis, acidity titration, pH, titration and ICP (inductively coupled plasma) to determine the progress of the cleaning processes. cleaning and to ensure that the concentration of the acid composition or cleaning solution remains within the desired operating limits.

Water temperature and level are also measured to ensure that the system is operating within required limits. System readings are checked to see if evidence of foaming is occurring. If an operating limit is reached (for example, the temperature of the recirculating cleaning solution reaches the maximum recommended limit), then the acid or cleaning solution composition or operating conditions of the system are adjusted (for example, additional dilution water is added to cool the recirculating acid composition or cleaning solution and additional concentrated acid composition or the cleaning solution is added to maintain the concentration of acid composition or cleaning solution). Chemical analyzes of recirculating acid composition samples or cleaning solution were used to determine when the cleaning process is complete (e.g., levels of deposit-forming ions such as silica, hardness ions, aluminum, and the like reach a level substantially constant indicating that the cleaning process is complete), and that any corrosion of the internal surfaces of the evaporator by the acid composition 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 may be added, recirculated and drained as necessary to remove residual amounts of acid composition or cleaning solution remaining in the system. The evaporator is then filled with feedwater to achieve a normal operating level within the system. The recirculation water pumps are started and steam is normally added to the shell side of the heat exchanger to heat the recirculation water, the mechanical vapor compression pump is started and the system is brought back online.

The used acid composition or cleaning solution drained from the system is removed. The removal method may vary depending on the application site. One removal method is to neutralize the acid composition or cleaning solution with concentrated caustic soda until approximately a neutral pH is reached. The acid composition or neutralized cleaning solution can be disposed of by sending it to an off-site disposal facility. Another 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 discarded), and, then dispose of the liquid filtrate by injection into deep well disposal sites. The number and sequence of steps required in cleaning the evaporator and disposing of the used cleaning solution may vary depending on the application site and system design.

After having described 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.

ινΐΛ/a/zuzz/ui óól i

Examples

The following non-limiting examples are provided to better illustrate the present invention.

Example 1: Elemental Analysis of Deposits

The chemical composition of four deposits was determined by standard X-ray fluorescence (XRF) composition analysis for elemental composition, concentration of organics by C/H/N/S elemental analysis, and the concentrations of organics/water of hydration and others. volatile substances when heated to 925°C for a defined period of time. The results are shown in Table 3.

Table 3. Chemical composition of deposits

<td>Chemistry</td><td>Deposit #1</td><td>Deposit #2</td><td>Deposit #3</td><td>Deposit #4</td>

<td>As silica (as YES02)</td><td> 56%</td><td> 49%</td><td> 56%</td><td> 51%</td>

<td>Calcium (as CaO)</td><td> 15%</td><td> 41%</td><td> 11%</td><td> 5%</td>

<td>Sodium (as Na2EITHER)</td><td> 4%</td><td> 5%</td><td> 7%</td><td> 3%</td>

<td>Aluminum (ALO3)</td><td> <0.5%</td><td> <0.5%</td><td> 1%</td><td> 3%</td>

<td>Chlorine (as Cl)</td><td> 3%</td><td> <0,5%</td><td> 2%</td><td>Not detected</td>

<td>Magnesium (as MgO)</td><td> 2%</td><td> 1%</td><td> 1%</td><td> 8%</td>

<td>Potassium (as K2O)</td><td> <0.5%</td><td> <0.5%</td><td> 4%</td><td> 2%</td>

<td>Sulfur (as SO3)</td><td> <0.5%</td><td> <0.5%</td><td> <0.5%</td><td> 2%</td>

<td>Iron (as FesOa)</td><td> <0.5%</td><td> <0.5%</td><td> 1%</td><td> <0.5%</td>

<td>Organic</td><td> <0.5%</td><td> <0.5%</td><td> 5%</td><td> 14%</td>

<td>Application -></td><td>Evaporator</td><td>Once through HRSG</td><td>Evaporator</td><td>Evaporator</td>

probably due to hydration water and also includes organic products

Example 2: Dissolution of Materials

The test method consisted of weighing several grams (~3 g) of a standard solid in a 113.4 gram plastic jar. Followed by the addition of 100 ml of distilled water. Test acids were prepared at 5, 10, or 15% by weight of the product in distilled water. The lid of the flask was attached and the flask was shaken vigorously several times to completely wet the solid. If necessary, the cap is loosened to vent pressure development. During tests at room temperature, the flasks were shaken ~3 times per week (Method 1). During tests above temperature (75°C except where noted), flasks were stored in a circulating water bath with an integral stirrer (Method 2). Periodically, samples (3 ml) were taken at least one hour after shaking. The samples (2 g) were then filtered by syringe through a 0.45 μ filter. The filtered samples were diluted with 98 ml of distilled water and sent for solid composition analysis using X-ray fluorescence (XRF) and X-ray scattering (XRD) methods. The elemental analysis is presented in Tables 4-13.

The acids tested were urea tetrafluoroborate (commercially available from Nalco-Champion as Product No. EC6697A/R-50975, identified as composition A hereinafter), urea sulfate (commercially available from Vitech International, Inc. as A85, identified as composition B hereinafter), modified urea tetrafluoroborate (commercially available from Vitech International, Inc. as APW product, identified as composition C hereinafter), urea hydrochloride (commercially available from Vitech International, Inc. as BJS-I product, identified as composition D hereinafter), urea methanesulfonate (commercially available from Vitech International, Inc. as product M5, identified as composition E hereinafter), hydrochloric acid (identified as composition F hereinafter), urea tetrafluoroborate (commercially available from Vitech Internationally, Inc. as product ALB, identified as composition G hereinafter) and modified urea hydrochloride (commercially available from Vitech International, Inc. as product BJS-HT, identified as composition H hereinafter), product N2560 (commercially available from Nalco-Champion, identified as composition I hereinafter), inhibited hydrochloric acid, commercially available from Nalco Champion as N2560 and urea hydrofluoride ( commercially available from Nalco Champion as product DC14, identified as composition J hereinafter).

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

Table 4. Dissolution of magnesium silicate hydroxide (talc) using 15% by weight of acid

ΜΛ/a/zuzz/u 1 ¿¿ii

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>AND</td><td>d</td>

<td colspan="7">Method 2</td>

<td rowspan="2">2 hours</td><td>Mg as Mg</td><td> 462</td><td> 82</td><td> 459</td><td> 34</td><td> 25</td>

<td rowspan="2">6 hours</td><td>Mg as Mg</td><td> 1332</td><td> 227</td><td> 1362</td><td> 141</td><td> 111</td>

<td rowspan="2">24 hours</td><td>Mg as Mg</td><td> 2778</td><td> 395</td><td> 3410</td><td> 280</td><td> 251</td>

<td rowspan="2">48 hours</td><td>Mg as Mg</td><td></td><td> 447</td><td></td><td> 313</td><td> 298</td>

Table 5. Dissolution of magnesium silicate hydroxide (florisil) using 15% by weight of acid

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

<td colspan="7">Method 2</td>

<td rowspan="2">2 hours</td><td>Mg as Mg</td><td> 1640</td><td> 1657</td><td> 1526</td><td> 1451</td><td> 999</td>

<td rowspan="2">6 hours</td><td>Mg as Mg</td><td> 2104</td><td> 2338</td><td> 1990</td><td> 2343</td><td> 2213</td>

<td rowspan="2">24 hours</td><td>Mg as Mg</td><td> 2103</td><td> 2152</td><td> 2093</td><td> 2189</td><td> 2136</td>

to Values are in units of mg/l.

Table 6. Alumina dissolution using 15% by weight of acid

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

<td colspan="7">Method 2</td>

<td>6 hours</td><td>Al as Al</td><td> 1414</td><td> 692</td><td> 1051</td><td> 299</td><td> 77</td>

<td>24 hours</td><td>Al as Al</td><td> 7233</td><td> 3467</td><td> 6236</td><td> 1782</td><td> 359</td>

<td>48 hours</td><td>Al as Al</td><td></td><td> 6519</td><td></td><td> 3234</td><td></td>

to· Values have units of mg/l.

Table 7. Dissolution of magnesium oxide using 15% by weight of acid

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

to Values have units of mg/L.

Table 8. Dissolution of calcium metasilicate using 15% by weight of acid

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

<td colspan="7">Method 2</td>

<td rowspan="2">6 hours</td><td>Ca as Ca</td><td> 6380</td><td> 1437</td><td> 6017</td><td> 4196</td><td> 3303</td>

<td rowspan="2">24 hours</td><td>Ca as Ca</td><td> 6448</td><td> 1428</td><td> 6754</td><td> 8083</td><td> 7337</td>

<td rowspan="2">48 hours</td><td>Ca as Ca</td><td> 6006</td><td> 907</td><td> 6017</td><td> 7144</td><td> 6507</td>

<td colspan="7">Method 3b</td>

to- Values have units of mg/L.b Same as method 2, except that the temperature was set at 29°C. Composition C and D were prepared as 5% by weight.

Table 9. Calcium fluoride solution using 15% acid by weight

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

TO- Values have units of mg/l.

Table 10. Aluminum silicate solution with 15% by weight ινΐΛ/a/zuzz/ui óói i of acid

<td colspan="7">Method 1</td>

<td></td><td></td><td colspan="5">Composition</td>

<td>Time</td><td>Element</td><td>TO</td><td>b</td><td>c</td><td>d</td><td>AND</td>

<td colspan="7">Method 2</td>

<td rowspan="2">6 hours</td><td>To the</td><td> 2162</td><td> 57</td><td> 2335</td><td> 29</td><td> 26</td>

<td rowspan="2">24 hours</td><td>To the</td><td> 4803</td><td> 236</td><td> 4738</td><td> 95</td><td> 78</td>

<td colspan="7">Method 3b</td>

to- Values have units of mg/l.b Same as method 2, except the temperature was set at 29°C.

<td colspan="7">Method 2</td>

<td rowspan="3">6 hours</td><td>To the</td><td> 431</td><td> 161</td><td> 264</td><td> 316</td><td> 49</td>

<td rowspan="3">24 hours</td><td>To the</td><td> 478</td><td> 318</td><td> 477</td><td> 504</td><td> 91</td>

<td rowspan="3">48 hours</td><td>To the</td><td> 505</td><td> 395</td><td> 545</td><td> 596</td><td> 130</td>

to- Values have units of mg/l.

Example 3: Corrosion Rate Titration Study

Various net acids used in the titration were studied to evaluate their corrosion rates. A test liquid was prepared by dissolving sodium carbonate (35.3 g) and sodium chloride (14.4 g) in 2 liters of distilled water. The test fluid was placed in a 5 liter beaker with a magnetic stirring bar. The stirring speed was adjusted to ensure good mixing without introducing bubbles into the test fluid. A hardened steel Nalco corrosion monitor (NCM) and pH probes were installed in the fluid. The probes were then connected to a TRASAR® 3D controller to record data. Aliquots of a net acid were added to the test fluid and readings were obtained. The titration was continued until the pH of the fluid went beyond the range of interest. The pH was adjusted to a pH value of 4. The net acids used in this study were compositions A, H, and I. The results of this study are shown in Figure 1.

It should be noted, the NCM probe readings took about 9 minutes each, so the titration aliquots required at least 20 minutes to equilibrate.

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

Example 4: Determination of Corrosion Rate with Bar Style Specimens

Hardened steel specimens (Nalco Product No. P5035A) were used to evaluate the corrosion rates of different acids and acids in combination with corrosion inhibitors. Test acids were prepared as 5, 15, or 25 wt% solution in distilled water. Corrosion inhibitors were prepared as 0.5, 1.0, 2.0 or 3.0 wt% solution in distilled water. The test fluid (approximately 450 ml) was added to a wide mouth plastic bottle (500 ml). Various amounts of corrosion inhibitor(s) were added to the bottle, the bottle was capped, and the bottle was shaken to mix the two liquids. Three hardened steel specimens were attached to a perforated cap via non-metallic bonding and the height was adjusted to be suspended below the fluid surface. The test tubes were spaced evenly around the lid so that they did not come into contact with each other. The perforated lid and test tubes were installed in the wide-mouth flask and the flask was placed in a circulating water bath. The circulating water bath was set at 65, 75, or 90°C. Then a plastic tube connected to an airline was inserted through the center hole of the lid. The air flow was set between 5 to 10 ml/minute.

The test tubes were removed, one after each time point (6, 24, and 48 hours), cleaned with a mild plastic cleaner, and rinsed once with distilled water and twice with acetone to dry. The specimens were placed in a desiccator to equilibrate the temperature.

After cleaning and temperature equilibration, the specimens were weighed and the corrosion rate was calculated. The corrosion rate was calculated from the weight loss of the specimen, exposure time and surface area of the specimen.

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

Example 5: 48 Hour 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 liters of distilled water. The specimens were pretreated ten times with the product for 72 hours at 90°C. Approximately 8 liters of the prepared solution were titrated with acid to a pH between 3.8 and 4.0 to remove all CO2 emissions, diluted to 9 liters and allowed to equilibrate overnight at 40°C. After equilibration, the solution was further diluted to 10 liters and the tempering was raised to 90°C. The test tubes and pH and NCM probes were installed in the test cell. The acids used in this study include compositions D and E. The corrosion inhibitors used in this study include a mixture of organic quaternary amines, tallow oil, fatty acid and the like (commercially available from Nalco Champion as product TX16010, identified as composition K hereinafter). Four test conditions were set, D, F, D with K and D with L. After 48 hours, the specimens were removed, cleaned and weighed as described in Example 4.

Example 6: Determination of Hybrid Corrosion Rate Using Bar Style Specimens and Composition D

A hybrid corrosion rate study was carried out, from Example 5 described above. A test fluid 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 balanced solution was 3.06. The solution was added to a wide-mouth plastic bottle and the test tubes (Nalco P5035A) were attached evenly around a perforated lid. The bottle was capped and an air line was attached with a flow rate of 5 ml/minute at 100% humidity. The study was conducted at a temperature of 75°C. The corrosion rate was measured in millimeters per year (mmpy) and microns per year (mpy).

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Table 14. Corrosion rate composition D

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 7: Determination of Hybrid Corrosion Rate Using Bar Style Specimens and Composition A

A hybrid corrosion rate study was conducted as described in Example 6, with the exception that 40.0046 g of composition A was used in the test fluid. The pH of the solution was 3.75.

Table 15. Corrosion Rate of Composition A

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<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 8: Determination of Hybrid Corrosion Rate Using Bar Style Specimens and Composition B

A hybrid corrosion rate study was conducted as described in Example 6, with the exception that 16,535 g of composition B was used in the test fluid. The pH of the solution was 3.75.

Table 16. Corrosion rate of Composition B

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 9: Determination of Hybrid Corrosion Rate

Using Bar Style and Composition F Specimens

A hybrid corrosion rate study was conducted as described in Example 6, with the exception that 43.89 g of composition F was used in the test fluid. The pH of the solution was 3.75.

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Table 17. Corrosion Rate of Composition F

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 10: Determination of Corrosion Rate Using Bar Style Specimens, Composition B and a Corrosion Inhibitor

A corrosion rate determination study was conducted using bar-style specimens, an acid, and a corrosion inhibitor. 15% by weight of composition B was prepared by adding 75 g of composition B to 423 g of distilled water. To this was added 2.5 g of composition H. The solution was added to a wide-mouth plastic bottle and the test tubes (Nalco P5035A) were uniformly attached around a perforated cap. The bottle was capped and an air line was connected with a flow rate of 5 ml/min, with 100% humidity. The study was carried out at a temperature of 75°C.

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Table 18. Corrosion Rate of Composition B

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td>Speed</td><td>of</td><td>corrosion</td>

Example 11: Determination of Corrosion Rate Using Bar Style and Composition E Specimens

A corrosion rate determination study was performed as described in Example 6, with the exception that 75 g of composition E and 420 g of distilled water were used.

Table 19. Composition E Corrosion Rate

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 12: Determination of Corrosion Rate Using Bar Style Specimens, Composition C and a Corrosion Inhibitor

A corrosion rate determination study was carried out as described in Example 9, with the exception that 75 g of composition C, 5 g of composition I and ινΐΛ/a/zuzz/ui óól í were used.

420 g of distilled water.

Table 20. Corrosion Rate of Composition C

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 13: Determination of Corrosion Rate Using Bar Style Specimens, Composition C and a Corrosion Inhibitor

A corrosion rate determination study was carried out as described in Example 9, with the exception that 75 g of composition C, 5 g of composition I and 415 g of distilled water were used.

Table 21. Corrosion Rate of Composition C

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 14: Determination of Corrosion Rate Using Bar Style Specimens and Composition D

A corrosion rate determination study was performed as described in Example 9, with the exception that 75 g of composition D, no corrosion inhibitor, 425 g of distilled water, and 8.24 g of sodium chloride were used.

Table 22. Corrosion Rate Composition D

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 15: Determination of Corrosion Rate Using Bar Style Specimens and Composition A

A corrosion rate determination study was performed as described in Example 9, with the exception that 75 g of composition A, no corrosion inhibitor, 425 g of distilled water, and 4.12 g of sodium chloride were used. .

Table 23. Corrosion Rate of Composition A

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<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 16: Determination of Corrosion Rate Using Bar Style Specimens and Composition B

A corrosion rate determination study was performed as described in Example 9, with the exception that 75 g of composition B, no corrosion inhibitor, 425 g of distilled water, and 4.12 g of sodium chloride were used.

Table 24. Corrosion Rate of Composition B

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 17: Determination of Corrosion Rate Using Bar Style and Composition E Specimens

A corrosion rate determination study was performed as described in Example 9, with the exception that 75 g of composition E, no corrosion inhibitor, 425 g of distilled water, and 4.12 g of sodium chloride were used.

Table 25. Corrosion Rate Composition E

<td>Test tube</td><td>Composition</td><td>Weight loss (g)</td><td colspan="2">corrosion rate</td>

Example 18: Laboratory Scale Test

The cleaning composition used in these tests was 15% v/v of a composition in water.

A simple laboratory benchtop unit was designed and constructed to evaluate new cleaning chemicals under dynamic conditions. This laboratory bench unit is represented by Figure 2. The test reservoir 250 was placed in a test reservoir 240 that was in fluid connection with the cleaning solution reservoir 230. The cleaning solution reservoir 230 was placed in a 210 temperature controlled water bath. The cleaning solution was pumped through a 220 pump from the cleaning solution tank 230 to the test tank 240.

The test apparatus evaluated various cleaning chemicals to obtain data regarding performance and possible cleaning methods (including temperature, concentration and time). Additionally, programs and recommendations can be developed for specific deposits. The results translated to improving their performance on the field. Figure 3 is a schematic view of the laboratory scale dynamic testing apparatus.

The test method consisted of maintaining the cleaning solution at a constant temperature while the cleaning composition was recirculated through a field reservoir sample. Field samples used for the experiment were analyzed for composition and then dried at 105°C. The initial sample weight was taken in the dried tank, as received. The tank sample or object with tank attached thereto was immersed in the flowing cleansing solution for the prescribed test period. The cleaning solution can be heated with test temperatures of 60°C or 80°C normally used. The entire container for the deposit sample was also immersed in the heating bath. When the test was complete, the remainder of the tank was rinsed with deionized water and bottled dry. The recovered residual deposit was dried at 105°C. The final weight of the dry deposit was taken and used to determine the % dissolution. Aliquots of the test solution could be removed during the test to evaluate ion concentrations using ICP spectroscopy and treatment performance was measured as cleaning progressed. This procedure allowed for several cleanings, variable temperatures and times.

The test method consisted of maintaining the cleaning solution at a constant temperature while the cleaning composition was recirculated through a field reservoir sample. Field samples used for the experiment were analyzed for composition and then dried at 105°C. The initial sample weight was taken in the dry tank, as received. The tank sample or object with tank attached thereto was immersed in the flowing cleaning solution for the prescribed test period. The cleaning solution could be heated with test temperatures of 60°C or 80°C normally used. The entire container for the deposit sample was also immersed in the heating bath. When the test was complete, the remainder of the tank was rinsed with deionized water and bottled dry. The recovered residual deposit was then dried at 105°C. The final weight of the dry deposit was taken and used to determine the % of the solution. Aliquots of the test solution could be removed during the test to evaluate ion concentrations using ICP spectroscopy and treatment performance was measured as cleaning progressed. This procedure allowed for multiple cleanings, variable temperatures and times.

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

Laboratory studies were conducted to measure the dissolution of metallic and organic silicate-based evaporator deposits from the application site. Figure 6 shows that the deposition dissolution results strongly depended on the concentration of the cleaning solution (0-15% v/v). Very good results of 85% deposit removal dissolution occurring with a 15% v/v concentration of the cleaning composition were obtained at 60°C after 22 hours.

Figure 7 shows that hardness and silica ions were rapidly released from an evaporator reservoir sample in the water distributor cap during the first five to ten hours of treatment at 60°C. This rapid period of deposit dissolution was followed by a decrease in dissolution rate from 10 to 22 hours, as almost the entire deposit was dissolved and the most resistant portions of the deposit were attacked.

Figure 8 demonstrates that the sump reservoir dissolution with the cleaning composition shows similar trends as Figure 6 (distributor cap reservoir dissolution).

Example 19: Deposit Dissolution Tests

Due to the different compositions, particle sizes and surface areas, each of the deposits were ground with a mortar and pestle then sieved through a #14 sieve so that each of the samples had a particle size and similar 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 5.08 centimeter octagonal stir bar of known weight on a hot stirring plate set at a temperature of 55-60°C and a mixing speed of 5.5 for 90 minutes before the addition of 5.0 grams of the scale deposits.

The flake deposit (5.0 g) was added to the preheated test solution and mixed for 16 h at the same temperature and mixing speed. After 16 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 bar, and filter paper were recorded. The percentage of dissolved material was then calculated as follows:

Percentage of dissolved deposit = {[Initial Scale Weight - Total Residual Weight (TRW)]/Initial Scale Weight }* 1 00

Table 26. Deposit Dissolution Results

<td>Chemical cleaning</td><td>% of deposit dissolved #1</td><td>% of deposit dissolved #2</td><td>% of deposit dissolved #3</td><td>% deposit dissolved #4</td>

<td>Composition A</td><td> 80%</td><td> 91%</td><td> 80%</td><td> 69%</td>

Example 20: Pilot Scale Boiler Tests

A pilot scale boiler (PSB) rig was used to evaluate the effectiveness of treatment chemistries and combinations of these treatments. The equipment was also used to evaluate the impact of changes in water quality and operating conditions. The PSB equipment is designed to provide a rapid indication (within five days) of long-term performance in larger plant unit operations.

The PSB of Figure 4 has feedwater fed from feed tanks 310, a pump connecting the feed tanks 310 to the degasser 320, a boiler feedwater (BFW) pump 330 connecting the degasser 320 and the boiler 340. , a heating cartridge 350 contained in the boiler 340, a condensate outlet stream 360 and a purge stream 370.

During testing of treatment chemicals and operating conditions, the PSB equipment was run under more severe conditions/pressure (water chemistry, heat flux and residence time) than the SAGD plant boilers and steam generators, at in order to reduce the time necessary to determine the results (Table 27).

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Table 27. Typical comparative operating conditions for PSB versus OTSG testing

<td>Parameter</td><td>Pilot Scale Boiler</td><td>Location #1</td>

<td>Design</td><td>Drum</td><td>OTSG</td>

<td>Power source</td><td>Heating Cartridge Electrically Heated</td><td>Natural gas</td>

<td>Vapor pressure</td><td>10,340 kPa (1500 psig).</td><td>9,653 kPa (1400 psig).</td>

<td>Steam temperature</td><td>314°C</td><td>309°C</td>

<td>Initial Heat Transfer Tube Wall Temperature</td><td>up to 344°C</td><td> ___</td>

<td>Heat flux</td><td>up to 361 kW/m2 (114,000 BTU/ft2/hr)</td><td>Consult note*</td>

<td>Retention Time 50% (or Residence Time)</td><td>~1.5 hours</td><td><2 minutes (estimate)</td>

<td>Concentration Cycles (or Vapor Quality)</td><td> 10</td><td>5 (80% quality)</td>

*typical heat flux range indicated in the literature is 47-125 kW/m2 or 15,000-40,000 BTU/ft2/hour (Gwak, K.-W., Bae, W. (2010). A Review of Steam Generation for In-Situ Gil Sands Projects. Geosystem Engineering 13(3), 114).

The water chemistry used for PSB testing is summarized in Table 28. The tests were run in 10 concentration cycles and the water within the PSB (measured as blowdown) will be 10 times more concentrated across all feedwater chemistries - if deposition does not occur. The feedwater chemistry and PSB concentration cycles 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 chemicals in OTSG purge and PSB tests are easily adaptable to a wide variety of water chemistries and operating conditions.

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Table 28 Boiler Chemistry Pilot Scale (mq/l) (water feed and 10 X concentration cycles) versus

OTSG*

<td>Property chemistry</td><td>x10 cycles of PSB feed water (mg/l)</td><td>Feedwater Location #1 x 4 cycles*</td>

<td>Calcium (as Ca)</td><td> 1.2</td><td> 1.2</td>

<td>Magnesium (as Mg)</td><td> 1.0</td><td>< detection limit</td>

<td>Silica (as SiO2)</td><td> 300</td><td> 100</td>

<td>Sodium (as Na)</td><td> 2,680</td><td> 3,920</td>

<td>Chloride (as Cl)</td><td> 3,870</td><td> 4,040</td>

<td>Lithium (as Li)</td><td> 6.0</td><td> 4.4</td>

<td>Conductivity (pS)</td><td> 13,500</td><td> 17,040</td>

*corresponding to 75% vapor quality and does not assume deposition occurs (for comparison)

As shown in Table 28, the water quality used for PSB testing at 10 concentration cycles is generally more severe than SAGD location #1 which operates at 75% vapor quality (4 concentration cycles) and is suitable for perform accelerated testing with equipment such as PSB. The volatilization of silica in steam is small (approximately 0.5%) under these operating conditions versus the concentration of silica in the boiler or blowdown water (Nalco (2004), Selective Carryover, Technifax TF-5, 1-3). The water modifications and operating conditions listed above can be performed when PSB equipment is used to evaluate operating conditions and treatment programs for a variety of SAGD plant locations or other boiler types (e.g., package or utility).

Table 29. Scale Boiler Performance Results

Pilot for a Variety of Treatment Options

<td>Feed water treatment</td><td>thermal deposition rate*</td><td>Deposition rate (mg/hr)*</td>

<td>Nalco Product No. 3DT156</td><td> -75</td><td> 3.15</td>

<td>Composition A**</td><td> 158</td><td> 1.60</td>

<td>Composition A** with Nalco Product No. 3DT156</td><td> -190</td><td> 0.42</td>

Lower values indicate better results

Concentration of ~30 mg/l as product in feed water

The overall performance results listed in Table 29 indicate that the lowest combination of thermal deposition rate and deposition rate (mg/hr) were obtained using a cleaning solution treatment combination (at doses of approximately 30 mg /l) and surfactant added to PSB feed water.

Example 21: Antifoam Agent Tests

A cleaning composition comprising 15% v/v of composition A in water was used to evaluate the effectiveness of various antifoam agents. The cleaning composition (10 grams) and the prescribed amount of antifoam agent were added to each test tube. The height of the liquid in each test tube was measured in mm and recorded before shaking. Each tube was covered with parafilm, shaken vigorously for one minute, and the foam height was measured in millimeters and recorded. The % foam height after one minute of stirring of the test solution and one minute of settling of the test solution was determined by dividing the foam height by the initial height of the liquid and multiplying the result by 100. This % of foam foam height was recorded. The test solution was then allowed to sit for 30 minutes and the persistence of foam in the test solutions was recorded as yes or no.

The antifoam agents tested were nonionic silicone (commercially available from Nalco, Inc. as Product No. 336FG, identified as M hereinafter), an ethoxylated, propoxylated C14-C18 alcohol (commercially available from Nalco, Inc. as Product No. .00PG-007, identified as N hereinafter), alkoxylated nonionic CeCium alcohol comprising both propoxy and ethoxy groups (commercially available from Nalco, Inc. as Product No. R-50360, identified as O hereinafter), prop i I eng I i co I nonionic, ethylene glycol block copolymer (commercially available from Nalco, Inc. as Product No. PP103038, identified as P hereinafter) , an ethoxylated C11-C14 alcohol (commercially available from Nalco, Inc. as product No. PP10-3148, identified as Q hereinafter), a propylene glycol oxide polymer (commercially available from Nalco, Inc. as Product No. 7906, identified as R hereinafter), a C16-C18 alcohol (commercially available from Nalco, Inc. as

Product No. 7465, identified as S hereinafter).

Table 30. Percentage of Foam Height Results*

<td>Antifoam</td><td>0 mg/l (blank)</td><td>10 mg/l</td><td>100 mg/l</td><td>1,000 mg/l</td><td>10,000 mg/l</td>

<td>EITHER</td><td></td><td> 65%</td><td> 23%</td><td> 24%</td><td> 6%</td>

*Lowest % is the best result

Table 31· Foam Persistence Results*

<td>Antifoam</td><td>0 mg/l (blank)</td><td>10 mg/l</td><td>100 mg/l</td><td>1,000 mg/l</td><td>10,000 mg/l</td>

<td>EITHER</td><td></td><td>Yeah</td><td>Yeah</td><td>Yeah</td><td>No</td>

*No foam persistence is the best result

As shown in Tables 30 and 31, the antifoaming agents showing the most advantageous results were M, O and R. As can be seen from the results, some of the antifoaming agents were not effective in reducing foaming in the solution. cleaning. In particular, M and N antifoam agents are the most effective of the antifoam agents tested. The cleaning environment was one of high acid content, high conductivity, a high concentration of the cleaning solution and an unusual urea tetrafluoroborate compound, as well as other evaporator operating conditions of high temperature and presence of contaminant ions.

Example 22: Field Tests

Based on very positive laboratory results for the dissolution of deposits obtained from evaporators, a large scale evaporator cleaning was carried out. To begin cleaning, the system was taken offline, drained, and flushed with utility water. A known volume of utility water was added to the evaporator and then the concentrated cleaning composition was added to provide a concentration of approximately 15% v/v. Since the evaporator was recently taken offline, the system was still hot at the beginning of the cleaning process. Some difficulty was initially encountered in maintaining in-line temperature readings of the cleaning solution below the recommended limit of 80°C.

After the initial addition of the cleaning solution, a severe foaming situation was detected inside the evaporator based on wide fluctuations in water level measurements. Foaming is a serious problem that must be avoided and quickly corrected when detected because it can cause alarms/safety switches to activate, can cause cavitation to form in recirculation pumps, can limit recirculation of internal fluids, can cause vibration of the system, and may result in fouling of the defrost system, which results in contamination of the evaporator distillate and serious consequences for the evaporator system. The foaming that occurred was unexpected and was resolved by adding an antifoam with a composition similar to M at a dose of approximately 40 mg/L. The foaming within the evaporator system disappeared and it was possible to continue the chemical cleaning process using a composition cleaning of 15% v/v of composition A.

It was also observed during the cleaning process that the temperature of the cleaning solution tended to increase 2-3°C/hour based on the pumping energy added to the system 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.

Notable reductions in temperature represent periods when significant amounts of cold utility water + fresh cleaning composition are added to the existing cleaning solution. Subsequent improvements in the cleaning procedure have greatly reduced the need to add more utility water to cool the system.

The progress of the evaporator cleaning process was verified by analyzing simple samples of cleaning solution from primary and secondary collectors. ICP spectroscopy was used to measure the concentrations of aluminum, calcium, magnesium, and silica from dissolution deposits. ICP (iron chromium) spectroscopy was also used to determine if any significant corrosion was occurring on the internal surfaces of the evaporator system during cleaning. The concentration of the cleaning composition was determined by a simple titration procedure and additional treatment was added to maintain approximately 15% v/v cleaner concentration, as necessary.

Since the volume of the cleaning solution increased during the cleaning process, the ICP spectroscopy results need to be compensated for changes in the volume of the system, which produces dilution in the concentrations of the analyzed species. A comparison of ICP spectroscopy readings for silica concentration (uncorrected vs. corrected system volume) of the cleaning solution samples is shown in Figure 9.

It is evident that ICP spectroscopy readings corrected for changes in the volume system during evaporator cleaning is very important in the correct interpretation of the results. The uncorrected analytical results suggest that the cleanup was completed after several hours. The use of uncorrected analytical results could have led to the decision to end the cleaning process before it was completed. In reality, the removal of silicate-based deposits occurred during the entire 25-hour cleaning period. Although most of the silica deposits were released during the first hours of cleaning, the most tenacious deposits were probably removed during 5-25 hours of cleaning. Additionally, using volume-corrected results showed approximately 70% more dissolution of silica-based deposits compared to uncorrected ICP spectroscopy results. Based on the above trends, the corrected system volume results will be used for the remainder of the discussion.

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

The simple samples of cleaning solution obtained during the cleaning process presented a very dark color, indicating a high level of organic compounds that were probably removed from the deposits through the cleaning composition. Dark-colored substances that precipitated from the cleaning samples over time were collected and measured using a C/H/N analyzer. The analytical results showed that around 700 mg/l of organic compounds were present, indicating that the cleaning composition is capable of removing inorganic and organic base deposits.

In addition to analyzing samples of the cleaning solution to quantify the dissolution of organic and inorganic deposits, those same samples were also measured for chemical evidence of general corrosion on the internal surfaces of the evaporator. The largest internal surface area of the evaporator that is cleaned is AL6XN®, 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 (Allegheny Technologies Inc., 2014). The evaporator heat exchanger tube bundles 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 samples. Those analyzes were combined with information on evaporator surface area, AL-6XN specific gravity, and cleaning solution volume to estimate the overall corrosion rate of AL-6XN. Figure 12 shows the estimated overall corrosion rate of AL-6Xn and the temperature of the cleaning solution (average of primary and secondary readings) during the cleaning process.

The estimated corrosion rate (refer to Figure 13) increases as the temperature of the cleaning solution increases, a reasonable response. The maximum overall corrosion rate on AL-6XN estimated from cleaning fluid analysis was 1.9 mpy (48 pm/year), which is well below the allowable limit of 50 mpy (1270 pm/year) established by the customer. Since the use of Cleaning Treatment A is normally a 1 or 2 day process, a negligible increase of -0.005-0.01 mpy (-0.13-0.26 pm/year) for each cleaning would be added to the entire annual corrosion rate of AL-6XN.

The 15% v/v composition cleaning solution was able to remove deposits from the entire 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 the secondary evaporator system during inspection. However, it was observed that the residual deposits after chemical cleaning were much easier to remove by mechanical cleaning. Further refinements in the application of the cleaning composition and repeated cleanings over time of the evaporator system could inhibit the formation of tenacious deposits in the wetted portion of the evaporator after chemical cleaning. Inspections of evaporators using a 15% v/v cleaning composition solution have shown that it is possible to clean the base metal surface throughout the primary and secondary systems.

After using 15% v/v of the cleaning composition solution to remove evaporator deposits, significant volumes of used cleaning solution (up to 200 m3 or more) may need to be removed before bringing the evaporator back online. During the initial cleaning of a plant evaporator, the cleaning solution used was neutralized with caustic soda and then removed by taking it off-site for disposal. Disposal of cleaning solution using on-site systems is preferable and less expensive. The test was conducted to ensure that the 15% v/v cleaning composition solution used would be fully compatible with the downstream wastewater treatment system. A test was also conducted on the caustic neutralization process of the cleaning solution used to ensure that the optimal pH for removal was obtained as quickly as possible without generating excessive heat. After the initial application of 15% v/v of the cleaning solution to the evaporator plant, up to the composition, all subsequent cleanings used the on-site wastewater treatment system to dispose of the neutralized cleaning composition, used. This resulted in an easier cleaning procedure and savings on waste disposal costs.

Example 23: Dissolving Deposit Pipeline Cleaning by One-Time Pigging Through Steam Generator (OTSG)

The test method consisted of weighing several grams (~3 g) of a solid OTSG pig pipe cleaning reservoir into a 113.4 gram plastic jar. Followed by the addition of 100 ml of distilled water. The test acid was prepared as 15% by weight of composition A in distilled water. The lid was attached to the jar and the jar was shaken vigorously several times to completely wet the solid. If necessary, the cap is loosened to vent pressure buildup. The flasks were stored in a circulating water bath heated to 75°C with an integral stirrer. Periodically, samples (3 ml) were taken at least one hour after shaking. The samples (2 g) were then syringe filtered through a 0.45 μ filter, dried, and percent dissolution was calculated.

<td>Composition</td><td>Hours</td><td>Dissolution (%)</td>

<td>Water</td><td> 5</td><td> 10</td>

When introducing elements of the present invention or preferred embodiments thereof, the articles a, an, the, “the” and said 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 other elements in addition to the elements listed.

In view of the foregoing, it will be seen that the various objects of the invention are achieved and other advantageous results are obtained.

Since various changes can be made to the above compositions and methods without departing from the scope of the invention, it is intended that the matter contained in the foregoing description and shown in the accompanying drawings should be construed as illustrative and not in a limiting sense.

Contents6

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Priority claims
Document	Office	Kind	Date
14469323	United States of America	–	2014-08-26
201414469323	United States of America	A	2014-08-26
201562206658	United States of America	P	2015-08-18
201562206669	United States of America	P	2015-08-18
62206658	United States of America	–	2015-08-18
62206669	United States of America	–	2015-08-18

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Document	Office	Kind
US2004192337A1	United States of America	A1	2004-09-30
US2004253964A1	United States of America	A1	2004-12-16
US2007202851A1	United States of America	A1	2007-08-30
US2007238455A1	United States of America	A1	2007-10-11
US7321773B2	United States of America	B2	2008-01-22
US2008119202A1	United States of America	A1	2008-05-22
US2010003976A1	United States of America	A1	2010-01-07
US7764961B2	United States of America	B2	2010-07-27
US7856236B2	United States of America	B2	2010-12-21
US2010323674A1	United States of America	A1	2010-12-23
WO2012087353A1	World Intellectual Property Organization (WIPO)	A1	2012-06-28
US2012178443A1	United States of America	A1	2012-07-12
US8249589B2	United States of America	B2	2012-08-21
US8666397B2	United States of America	B2	2014-03-04
US2014135023A1	United States of America	A1	2014-05-15
US2014364145A1	United States of America	A1	2014-12-11
US2014364147A1	United States of America	A1	2014-12-11
US2014370916A1	United States of America	A1	2014-12-18
US9154906B2	United States of America	B2	2015-10-06
US2016014562A1	United States of America	A1	2016-01-14
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AR105725A1	Argentina	A1	2017-11-01
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EP3245270A1	European Patent Office (EPO)	A1	2017-11-22
JP2017535408A	Japan	A	2017-11-30
SV2017005394A	El Salvador	A	2018-02-26
US10035949B2	United States of America	B2	2018-07-31
EP3245270A4	European Patent Office (EPO)	A4	2018-12-19
AU2015308923B2	Australia	B2	2019-08-29
GT201700038A	Guatemala	A	2019-09-20
AU2019271980A1	Australia	A1	2020-01-02
EP3708633A1	European Patent Office (EPO)	A1	2020-09-16
EP3245270B1	European Patent Office (EPO)	B1	2020-09-23
JP6820833B2	Japan	B2	2021-01-27
JP2021007942A	Japan	A	2021-01-28
ES2839207T3	Spain	T3	2021-07-05
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AU2022203865B2	Australia	B2	2024-01-11
CA2995975C	Canada	C	2024-04-30
JP7483576B2	Japan	B2	2024-05-15
EP3708633B1	European Patent Office (EPO)	B1	2025-03-19

Fluro-inorganics for inhibiting or removing silica or metal silicate deposits.

Abstract

Term

ORGANIC FLUORO-1N TO INHIBIT OR REMOVE SILICA OR METAL SILICATE DEPOSITS

FIELD OF THE INVENTION

BACKGROUND OF THE INVENTION

BRIEF DESCRIPTION OF THE INVENTION

BRIEF DESCRIPTION OF THE DRAWINGS

DESCRIPTION OF PREFERRED MODALITIES

Priority claims6

Members61

Numbers

Titles2

Classification