NO883884L - PROCEDURES FOR TREATING HYDROCARBON RECOVERY OPERATIONS AND INDUSTRIAL WATER. - Google Patents

Description

This invention relates to chemical compounds with several purposes, which are used in hydrocarbon, e.g. oil and gas, extraction, production, transport, storage and refining operations and when treating industrial water, i.e. water used in industrial processes.

The invention relates in particular to nitrogen-containing dithiocarbamic acids and derivatives thereof with various applications.

Production of nitrogen-containing dithiocarbamic acids and

certain derivatives thereof are generally well known. Various types of such compounds have been described as having applications as fungicides, biocides, film formers, vulcanization accelerators, extreme pressure agents for lubricants and corrosion inhibitors.

The following patents are considered to be relevant in connection with the present invention.

US Patent Nos. 2,326,643, 2,356,764, 2,400,934, 2,589,209

and 2,609,389 describe products from the reaction between carbon disulphide and alkylene polyamines, the products being dithiocarbamic acids or their salts. US Patent Nos. 2,609,389 and 2,693,485 describe the products from the reaction between lower alkylene diamines and carbon disulphide and the use of such reaction products, the products being further reacted with aldehydes to form condensation polymers. US Patent No. 2,400,934 describes the product of the reaction between 1-diethyl-amino-4-aminopentane and carbon disulfide as an intermediate in a purification process. US Patent No. 2,326,643 describes polydithiocarbamate products from the reaction between carbon disulfide and aliphatic polyamines and their use as intermediates in a subsequent reaction. US Patent No. 2,356,764 describes monodithiocarbamate products from the reaction between alkylenediamines and carbon disulfide and the use of such products as film formers.

US Patent No. 2,561,208 describes products from the reaction between carbon disulphide and diamines with cyclohexyl groups in their chain, and their use in the manufacture of rubber vulcanization accelerators, bactericides and fungicides.

US Patent No. 2,733,262 describes products from the reaction between carbon disulphide and N-(hydroxyalkyl)alkylene diamines, the reaction products being bisdithiocarbamic acids with agricultural fungicide activity.

US Patent No. 3,392,192 describes internal salt products from the reaction between carbon disulphide and internally alkoxylated diamines, such products being used as corrosion inhibitors and as extreme pressure agents for lubricants.

One aspect of the present invention relates to the new uses of certain nitrogen-containing dithiocarbamic acids and derivatives thereof in a number of industrial applications, particularly in the treatment of fluids associated with hydrocarbon extraction, production, transport, storage and refining operations and when treating industrial water.

Another aspect of the invention relates to new nitrogen-containing dithiocarbamic acids and derivatives thereof.

The compounds with new application in the methods according to the present invention are generically represented by the following formulas:

where:

R represents an organic radical; R± and R 2 each independently represent an organic radical which may be the same or different for each representation of R± and R 2 ; R 3 and R 6 each independently represent H or an organic radical which may be the same or different for each representation of R 3 and R 6 ; R 7 represents a cation; R8 represents

or other organic or inorganic radical; Rg represents

where R4 and R5

represents H or an organic radical;

R 10 represents H or an organic radical;

m and mi each independently represent 0 or 1-500;

x and Xi each independently represent 0 or at least 1; and

y±'Y2 °9 y3independently represent 0 or at least 1.

Organic radicals which may be represented by R, R^, R2, R3, R4, R5, Rg, Rg, R9 and R10' include saturated and unsaturated aliphatic and cycloaliphatic radicals, aromatic radicals including fused ring systems, aliphatic-substituted aromatic radicals, aromatic-substituted aliphatic radicals, aliphatic-substituted heterocyclic radicals and polymers. The organic radicals may be substituted with functional groups that are well known to those skilled in the art, e.g. halogen, hydroxyl, nitro, cyano, amino, amido which are further described in the following.

The saturated aliphatic hydrocarbon radicals may be branched or unbranched and include alkyl (e.g. CH3-) radicals of 1-30 carbon atoms, alkylene- (e.g. -CH2-) radicals of 1-30 carbon atoms, alkylidene- (e.g. .eg CH3CH=) radicals with 1-30 carbon atoms, alkanetriyl- (e.g. C=) and alkanetetrayl- (e.g. C=) radicals with 1-30 carbon atoms and other corresponding poly-yl radicals with 1 -30 carbon atoms with 5 or more, e.g. up to approx. 30, open valences. Alkyl radicals thus include methyl, ethyl, propyl, butyl, amyl, hexyl, heptyl, octyl, nonyl, decyl, dodecyl, tetradecyl, hexadecyl, octadecyl, eicosyl, pentacosyl, triacontyl and the like. Alkylene radicals include methylene, dimethylene, trimethylene, tetramethylene, octadecylmethylene and the like. Alkylidene radicals include methylidene, ethylidene, butylidene, hexadecylidene, triacontylidene and the like. Alkanetriyl radicals include HC=, -CH2-CH= and -CH2—(C<H>2)3-2g CH=°9~CH2CHCH2-. Alkanetetrayl radicals include =C=, =CH-CH=, =CH—(CH2)3-33CH=, -CH2CHCHCH2- and the like. Alkane poly-yl radicals containing 5 or more free valences include CH3-(CH)5-CH3,

-CH2-(CH)17-CH2-, -C-(CH)12-(C)6-C- and the like.

The unsaturated aliphatic hydrocarbon radicals may be branched or unbranched and include alkenyl (eg CH2=CH-) radicals with 1-30 carbon atoms, alkenylene (eg -CH=C-) radicals with 1-30 carbon atoms , alkenylidene- (e.g. CH2=C=) radicals with 1-30 carbon atoms, alkentriyl- (e.g. -C=C=) radicals with 1-30 carbon atoms, alkenetetrayl- (e.g. =C= C=) radicals with 1-30 carbon atoms and other corresponding poly-yl radicals with 1-30 carbon atoms with 5 or more, e.g. up to approx. 30, open valences and the corresponding acetylenically unsaturated aliphatic hydrocarbon radicals. Alkenyl radicals thus include ethenyl, propenyl, butenyl, pentenyl, hexenyl, heptenyl, octenyl, nonenyl, dekenyl, dodekenyl, tetradecenyl, hexadecenyl, octadekenyl, eicosenyl, pentacosenyl, tri-acontenyl and the like. Alkenylene radicals include ethenylene, propenylene, butenylene, dekenylene, triaconenylene and the like. Alkenylidene radicals include propenylidene, dekenylidene, eicosenylidene and the like. Alkenetriyl radicals include -HC=C=, -CH2CH=C=, -H2C-fCH273<r>2TCH=C= and the like. Alkene tetrayl radicals include =C=C=, =C-CH2-CH=C= and the like. Alkene poly-yl radicals containing 5 or more free valences include CH3—(CHtyg- CH=CH-HC=, CH3—fCH)10 (C73-CH=CH2 and the like. The saturated cycloaliphatic hydrocarbon radicals include cycloalkyl-

radicals with 3-6 carbon atoms, cycloalkylene-

radicals with 3-6 carbons atoms and cycloalkylidene-

radicals with 3-6 carbon atoms. Thus, cycloalkyl radicals include cyclopropyl, cyclobutyl, cyclohexyl and the like. Cycloalkylene radicals include cyclopropylene, cyclobutylene, cyclohexylene and the like. Cycloalkylidene radicals include cyclopropylidene, cyclobutylidene, cyclohexylidene and the like. Cycloalkane-poly-yl radicals with 3-6 carbon atoms containing 3-6 free ones valences, e.g.

and similar, is

also included.

The unsaturated cycloaliphatic hydrocarbon radicals include

ter cycloalkenyl

radicals with 3-6 carbon atoms, cycloalkenylene radicals with 3-6 carbon atoms and cycloalkenylidene-

radicals

with 3-6 carbon atoms. Thus, cycloalkenyl radicals include cyclopropenyl, cyclobutenyl, cyclohexenyl and the like. Cycloalkenylene radicals include cyclopropenylene, cyclopentenylene

and similar. Cycloalkenylidene radicals include cyclopropenylidene, cyclohexenylidene and the like. Cycloalkane-poly-yl radicals with 3-6 carbon atoms containing 3-6 free valences, e.g.

and the like, are also included.

Other organic groups indicated within the definition of formulas (1) - (3) include:

aryl or aromatic poly-yl groups, either simple or

in fused ring systems, for example phenyl, biphenyl, naphthyl and the like;

aralkyl or aralkane-poly-yl groups, for example benzyl, phenylethyl, phenylhexyl, phenyloctyl, phenyldodecyl, naphthyldecyl, phenylheptenyl and the like;

alkaryl or alkylaromatic poly-yl groups, for example methylphenyl, propenylphenyl, styryl and the like;

heterocyclyl or heterocyclic polyyl groups, for example furanyl, pyrryl, isoxazolyl, oxazolyl, thiazolyl, thiazolinyl, thiazolidinyl, pyrazolyl, imidazolyl, pyranyl, pyridinyl, oxazinyl, diazinyl and the like;

carboxylic acid groups, e.g. -C(=O)OH and derivatives thereof, such as esters, salts and the like; -C(=0)SH and similar derivatives thereof; -C(=S)OH and similar derivatives thereof; -C(=S)SH and -N(H)C(=S)SHAnd the like;

polymer skeletons comprising carbon or silicon or carbon-silicon, carbon-oxygen or silicon-oxygen, which may be substituted as described below.

The above-described organic groups can be substituted with functional groups that are well known to those skilled in the art. It is thus intended that the substituents may be hydrocarbyl, e.g. alkyl, cycloalkyl, alkenyl, alkynyl, aryl, aralkyl, alkaryl or heterocyclyl as described in detail above; or they can be halogen, e.g. chlorine, fluorine, bromine; HOR-, where R can be a hydrocarbyl or heterocyclyl group; R=0, where R can be a hydrocarbyl group or heterocyclyl group; amino; amido; acetamido; benzamido; carbonyl; cyano; cyanato, nitro; nitroso; sulfonyl; sulfonamido; benzenesulfonyl; benzenesulfonamido; thiol; phospho; phosphono; phosphorus; phosphonamido and the like.

In addition to the above, R3, R4, R5 and R6 can be attached to nitrogen via such bonds as -0-, -S-, -N(H)-,~(CH2)x~(where x represents an integer) and - C(Rg, R10)-where Rg and R10 represent an organic group, -S-S-,

-C(=0)N=, -C(=S)N= and the like.

The group R7, discussed above, is for example represented by a cation such as an alkali metal ion, e.g. Na, K, Li; or an alkaline earth metal ion, e.g. Ca, Mg; or N(R3)4 or S(R3)3 or P(R3)4.

The sum of yi+y2+y3 is on average equal to 3-250, preferably 3-100, more preferably 3-50, especially from 3 to approx. 6.

This invention includes mixtures. For example, some of the structures described above are the normal reaction products formed by organic reactions, such as ethoxylation and propoxylation. In these mixtures, a given molecule Y + y + y » averages 3-500, where a is designato-!a 2a 3a pure for a given molecular structure. In the mixture of such molecules, each molecule is slightly different from other molecules in its sum y la2a +y *3a so that the average of all ;y +y +y (as a>a>) is a real number, i.e. a whole number±a*aYes

? 3

or a fraction of 3-250, preferably 3-10.0, more preferably 3-50, especially 3-6.

Within the framework of formulas (1) - (3), the following formulas represent compounds that have been found particularly suitable for the methods according to the present invention:

where R represents alkanetetrayl, cycloalkanetetrayl, aromatic tetrayl or R± represents the alkylene, R3 represents H, lower alkyl, benzyl or -C(=S)SR7; R 7 represents Na, K, Ca or NH 4 ; R 8 represents H or ; R 8 represents H or wherein R 4 and R 5 each represent H or -C(=S)SR 7 ; R 10 represents H or an organic group; and R and R 3 , together with their common nitrogen atom, may represent a ring structure; where R represents alkanetriyl, cycloalkanetriyl or aromatic triyl; R 2 represents lower alkylene or arylene; R 3 represents H, lower alkyl or aryl; R 8 represents -C(=S)SR 7 or -R 2 -N(H)C(=S)SNa; R 7 represents Na, K, Ca or NH 4 ; R 8 represents H or wherein R 4 and R 5 each represent H or -C(=S)SR 7 ; R 10 represents H or an organic group; and m represents 1-3; where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl; R 2 represents lower alkylene; R 3 represents H or lower alkyl; R 7 represents H or Na; R 8 represents -N(R 3 )C(=S)SR 7 ; R 8 represents H or wherein R 4 and R 5 each represent H or -C(=S)SR 7 ; R 10 represents H or an organic group; and , y2 and y3 each represent 0 or at least 1; where R represents alkanetetrayl, cycloalkanetetrayl or alkyl substituted aromatic tetrayl; R 2 and R 2 each represent lower alkylene; R 3 represents H, lower alkyl or aryl; R 6 represents H or -C(=S)SR 7 ; R 7 represents Na; R 8 represents -N(R 3 )C(=S)SR 7 ,; Rg represents where R4 and R5 each represent H or -C(=S)SR7; R 10 represents H or an organic group; m and m±each represent 1; and Y2°9 v3nver represents 0 or at least 1; where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl; R ± and R 2 each represent lower alkylene; R 3 represents H; R 6 represents H or -C(=S)SR 7 ; R 7 represents Na; R 8 represents -N(H)C(=S)SR 7 ; Rg represents

where R 4 and R 5 each represent H or -C(=S)SR 7 ;

R 10 represents H or an organic group; m and m^^each represent 1; and<y>1P<y>2 and y3 each represent 0 or at least 1;

where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl; R 1 and R 2 each represent lower alkylene, R 3 represents H; R 6 represents H or -C(=S)SR 7 ; R 7 represents Na; R 8 represents -N(H)C(=S)SR 7 ; R9 represents

R4

H or -N where R 4 and R 5 each represent H or

-C(=S)SR 7 ; R 10 represents H or an organic group; m and m-L each represent 1 and ylP<y>2 and<y>3 each represent 0 or at least 1. Representative compounds within the scope of formulas (A)-(F) include the following: In formulas (l)-(3) and (A )-(F) preferably represents R alkyl, alkylene,

alkylene amine, alkanetriyl, alkanetetrayl, aromatic triyl or cycloalkanetriyl, R^ and R 2 each represent alkylene, R 3 and R 4 each represent hydrogen or alkyl, R 5 and R 6 each represent H or -C(=S)SR 7 , R 7 represents Na, K or NH 4 and R 8 represents -N(H) C(=S)SR7. Particularly preferred compounds are represented by the formulas

R,R3= lower alkyl and together cycloaliphatic

R7= alkali metal, ammonium, phosphonium or sulfonium salt

or other aliphatic triyl R3 ,R4 = H, alkyl Rs = H, alkyl, -C(=S)SR7R7 = alkali metal, ammonium Ra<=>-N(H)C(=S)SR7

R,R2= lower alkylene R3/R4 = H, alkyl

R 3 /R 5 =H, -C(=S)SR 7

R7= alkali metal, ammonium

R,Ra = alkylene R3,R4 = H, alkyl R3/R6 - H, alkyl, R7= alkali metal, ammonium ra = 1-7

R = alkanetriyl or tetrayl R 1 = alkylene

R 3 , R , R 3 = H, alkyl, -C(=S)SR 7

R7= alkali metal, ammonium

Rg = H, -OH or -N(H)C(=S)SR7

Rm = H or—(OR-i-)— Ro

Y3

Yl•<y>2°9<y>3 each represents at least 1, the sum of<y>i+<y>2+y3 being equal to 3-250 on average.

In general, the methods for preparing the described compounds are well known to those skilled in the art. The compounds are thus produced by reacting carbon disulfide with a primary or secondary alkylamine, alkylene polyamine, polyalkylene amine or polyalkylene polyamine. In the case of formulas (C) - (F), an appropriate alcohol is alkylated and ammoniated before reaction with carbon disulfide.

Representative primary and secondary amines that can be used to prepare the compounds described herein include methylamine, ethylamine, butylamine, hexylamine, octylamine, octadecylamine, dimethylamine, diethylamine, dibutylamine, dihexylamine, dioctylamine, ethylenediamine, propylenediamine , dipropylenetriamine, triethylenetetramine, tripropylenetetramine "Tetrameen" 10 C commercially available from Akzo, triaminonoan, tetraethylenepentamine, bis(hexamethylenetriamine), diethylenetriamine, "Duomeen" EA-80 commercially available from Akzo, "Jeffamine" T-403 commercially available from Texaco and other alkylamines, alkylene polyamines, polyalkylene polyamines and the like, such as any primary or secondary amine represented by the formula

where R, R2,<R>3»R4»R5»Rg and x are mentioned in relation to the formulas (1)-(3) and R' represents H or an organic group.

In the preparation of compounds according to the formulas (C)-(F) include oxyalkylating agents which are reacted with the amine, ethylene oxide, propylene oxide, butylene oxide and the like and mixtures thereof.

The compounds according to the invention are used as reverse demulsifiers (demulsification of oil-in-water emulsions), corrosion and scale inhibitors, flocculating agents, biocides, flotation aids, water clarification agents, boundary surface regulating agents and antifoam agents.

The following examples must not be regarded as limiting the scope of the invention. They illustrate specific embodiments of the invention and the best way to carry it out.

Preparation of compounds

Example 1

Reaction:

(C4<H>9-)-2-NH+NaOH+CS2(C4H9) 2NC (=S) SNa+H20

Reactants:

Approach:

Into a 500 ml flask equipped with a magnetic stirrer, thermometer, dropping funnel and reflux condenser connected to an eth-alkali scrubber was placed 8.0 g of 50% NaOH, 71 g of water and 12.9 g of dibutylamine. This mixture was cooled externally in an ice bath to 10-15°C, and then 7.6 g of carbon disulfide was added over a period of 10 minutes with vigorous stirring while maintaining the reaction temperature below 15°C. After a further 10 minutes the ice bath was removed and the reaction mixture was allowed to warm to room temperature (25°C) and stirring was continued for 1 hour. Before transferring the final product, the reactor was blown out with nitrogen/air to remove any residual CS2 or

-H2S which could have been formed during manufacture.

In the same way, similar products are prepared using other mono- and diamines, e.g. ethylamine, propylamine, butylamine, cyclohexylamine, dibutylamine, dibenzylamine and the like.

Example 6

Reaction:

Reactants:

Procedure: As in Example 1.

Example 7 Reaction:

Reactants:

Procedure: As in Example 1.

Example 8

Reaction:

Reactants:

Procedure: As in Example 1.

Example 9 Reaction:

Reactants:

Procedure: As in Example 1.

Example 10

Reaction:

Reactants:

Approach:

As in Example 1.

Breaking of emulsions of the oil-in-water type

This aspect of the present invention relates to a method for dissolving or separating emulsions of the oil-in-water type, i.e. so-called reverse emulsions, in that the emulsion is subjected to the influence of the compounds according to this invention.

Emulsions of the oil-in-water type comprise organic oily materials which, although immiscible with water or aqueous or non-oil media, are distributed or dispersed as droplets throughout a continuous body of non-oil medium. The proportion of dispersed oily materials is in many and possibly most cases a minor proportion.

01jefelt emulsions, which contain small proportions of crude petroleum oil relatively stably dispersed in water or salt solution, are representative oil-in-water emulsions. Other oil-in-water emulsions include water vapor cylinder emulsions, where traces of lubricating oil are found dispersed in condensed water vapor from steam engines and steam pumps, wax-hexane-water emulsions which

found in awaxing operations in oil refining, butadiene-tar-in-water emulsions formed in the production of butadiene from heavy naphtha by cracking in gas generators and which are especially found in washbox water in such systems, emulsions of "flux oil" in steam condensate formed by catalytic dehydrogenation of butylene during the production of butadiene, styrene-in-water emulsions in synthetic-rubber plants, synthetic-latex-in-water emulsions formed in plants where copolymer-butadiene-styrene or synthetic GR-S is produced -rubber, oil-in-water emulsions found in the cooling water systems of petrol absorption plants, tube press emulsions from steam-driven presses in chalk pipe manufacturing, emulsions or petroleum residues in diethylene glycol formed by dehydration of natural gas.

In other industries and professional areas, emulsions of oil materials are found in water or other non-oil media, for example in the formulation of synthetic resin emulsion paint, milk and mayonnaise processing, ship ballast waste water and furniture polishing formulation. When cleaning equipment used to process such products, diluted oil-in-water emulsions are inadvertently, accidentally or accidentally formed. Removal of aqueous waste products is usually made difficult by the presence of oil-in-water emulsions. Steam distillation and other manufacturing methods sometimes cause the formation of oil-in-water emulsions from which it is difficult to extract the essential oils.

Essential oils include non-saponifiable materials such as terpenes, lactones and alcohols. They also contain saponifiable esters or mixtures of saponifiable and non-saponifiable materials.

In all such examples, a non-aqueous or oily material is emulsified in an aqueous or non-oily material with which it is not naturally miscible. The term "oil" is used herein to broadly cover the water-immiscible materials present as dispersed particles in such systems. The non-oil phase naturally includes diethylene glycol, aqueous solutions and other non-oil media,

in addition to water itself.

Oil-in-water emulsions contain proportions of dispersed phase that are very different. When the emulsion is a waste product resulting from water flushing of manufacturing areas or equipment, the oil content may be only a few parts per million. Resin emulsion paints contain a major proportion of dispersed phase. Naturally occurring oil field emulsions of the oil-in-water type contain crude oil in proportions varying from a few parts per million to approx. 20%, or even higher in rare cases.

This aspect of the present invention relates to the dissolution of these emulsions of the oil-in-water type which contain a smaller proportion of dispersed phase, i.e. in the range from 20%

down to a few parts per million.

Although the present invention relates to emulsions containing as much as 20% dispersed oily material, many of them contain substantially less than this amount of dispersed phase. In fact, most of the emulsions found during the development of this invention have contained approx. 1% or less dispersed phase. It is such oil-in-water emulsions with dispersed-phase volumes of the order of 1% or less that the present method is particularly aimed at. This does not mean that there is no strong boundary line and that, for example, an emulsion containing 1% dispersed phase will react to the process while one containing 1.1% of the same dispersed phase will remain unaffected. Generally, however, dispersed-phase proportions in the order of 1% or less prove most favorable for the use of the present method.

In emulsions with high proportions of dispersed phase, significant amounts of some emulsifying agent are probably present, which thus explains their stability. In the case of more dilute emulsions containing 1% or less dispersed phase, it may be difficult to explain their stability on the basis of the presence of an emulsifier in the conventional sense. For example, water vapor condensate often contains very small proportions of refined petroleum lubricating oil in extremely stable dispersion, and yet neither the water vapor condensate nor the refined hydrocarbon oil will show

to contain something suitable for stabilizing the emulsion.

In such cases, the stability of the emulsion must probably be declared on a basis other than the presence of an emulsifier.

The present method proves, as stated above, to be effective for dissolving emulsions containing up to approx. 20% dispersed phase. It is particularly effective when it comes to emulsions that do not contain more than approx. 1% dispersed phase, which emulsions are the most important considering their common occurrence.

The method that constitutes the present invention comprises subjecting an emulsion of the oil-in-water type to the influence of a compound of the type described herein, whereby the oil particles in the emulsion are caused to flow together to a sufficient extent that they rises to the surface of the non-oil layer (or sinks, if the density of the oil is higher), when the mixture is allowed to stand still after treatment with the compound.

In carrying out the present method for dissolving an oil-in-water emulsion, a compound according to the invention is introduced at any suitable location in the system and mixed with the emulsion in any desired manner, such as being pumped or circulated through the system or by mechanical agitation, such as by paddles or by gas agitation.

After mixing, the mixture of emulsion and added compound is allowed to stand still until the phases that make up the emulsion are separated. Deposition times and optimal mixing times will of course vary with the nature of the emulsions and the equipment available. The operation is, in the broadest sense, simply the introduction of a compound according to the invention into the emulsion, the mixing of the two to establish contact and activate coalescence, and usually the subsequent quiet deposition of the agitated mixture to form the aqueous and non-aqueous emulsion phase as layered layers.

The agitation can be achieved in different ways. The piping system through which the emulsion is led during processing can in itself provide sufficient turbulence to achieve a suitable mixture of reagent and emulsion. Diverter pipe

("baffled pipe") can be used to provide agitation. Other devices such as perforated-chamber mixers, wood-wool or mineral or gravel or steel filings packed tanks or beds, or stones or gravel or minerals in open channels or ditches may be advantageously used to provide mixing. Introduction of a gas, such as natural gas or air, into a tank or pipe in which or through which the mixture of compound and emulsion stands or passes, is often found suitable for providing the desired agitation.

It has been found that the feed rate of the compound, agitation and settling time have a certain interrelationship.

For example, the settling time required can be significantly shortened with sufficient agitation of suitable intensity.' If, on the other hand, agitation is not available but the deposition time can be extended, the method may give equally satisfactory results. The supply rate for the compound has an optimal range that is sufficiently wide to satisfy the tolerance ranges required for the changes encountered daily in commercial operation.

The details of the mechanical constructions which are necessary to produce ventilation which is suitable for the present purpose need not be given here. It is sufficient to state that any devices which can produce small gas bubbles in the main part of the emulsion can be accepted for use.

The order in which the compound and the aeration step are used is relatively unimportant. Sometimes it is most appropriate to treat the emulsion with the compound and then apply the aeration technique. At other times, it may be more advantageous to produce a highly foaming emulsion and then introduce the compound into such an aerated emulsion.

Any gas can replace air in an aeration step. Other commonly suitable gases include natural gas, nitrogen, carbon dioxide, oxygen and the like, the gas being used mainly because of its elevating effect. If a gas has a certain harmful effect on one or another component of the emulsion, it will of course be desirable to use another gas instead which is inert under the conditions of use.

The compounds according to the invention can be used alone or as mixtures, or they can in some cases be advantageously used mixed with other compatible oil-in-water demulsifiers.

The method is usually used simply by introducing small portions of the compound into an oil-in-water emulsion, agitating to ensure distribution of the compound and initial coalescence and allowing the mixture to stand until the oil phase separates. The proportion of compound required will vary with the nature of the emulsion to be dissolved. Generally, proportions of compound needed are from approx. 1 ppm (parts per million) to approx. 3000 ppm based on the volume of the emulsion being treated, but more or less may be needed in specific cases. Preferably used from approx. 10 ppm to 1000 ppm, especially from approx.

10 ppm to approx. 100 ppm.

A preferred method for carrying out the method for dissolving a petroleum oil-in-water emulsion is as follows: The well fluids, which consist of free oil, oil-in-water emulsion and natural gas, are passed through a conventional gas separator, then to a conventional steel oilfield tank with a capacity of, for example, 596,000 litres. In this tank, the oil-in-water emulsion falls to the bottom, is withdrawn and thus separated from the free oil. The oil-in-water emulsion withdrawn in this way is subjected to the influence of a compound according to the invention with the desired small proportion, the injection of the compound into the stream of oil-in-water emulsion being carried out by means of a conventional proportioning pump or chemical supply device . The proportion used is determined in each case by trial and error. The mixture of emulsion and compound then flows to a pond or sump where it remains still, and the previously emulsified oil is separated, rises to the surface and is removed. The separated water, which contains from relatively little to essentially none of the previously emulsified oil, is then discarded or recycled.

All of the compounds presented and described herein have applications as reverse demulsifiers. Preferably, however, compounds according to formulas (A)-(C) are used in this way since they exhibit the greatest effectiveness as reverse demulsifiers.

Example 11

Various compounds according to the invention were subjected to bottle testing to determine the effectiveness of the compounds as reverse demulsifiers. The products were tested in the following way: Test water (100 ml field water containing an o/w emulsion of formed water and oil) was placed in 150 ml test bottles. A certain amount of chemical was added to each bottle and the bottles were agitated by hand or machine shaking with 100 shakes. The bottles are examined. The purpose of the experiment is to determine how quickly the emulsion breaks, as well as the purity of the separated water. The results are listed in the following table:

The experiments indicate that all the tested compounds are effective as reverse demulsifiers.

Example 12

The compound of Example 9 was subjected to a further bottle test and was found to provide sparkling clear water with minimal agitation (50 shakes) at concentrations of 5-50 ppm with oil transfer of 30 ppm at 5 ppm chemical application and 10 ppm at 30 ppm chemical application.

Example 13

The compound of Example 9 was field tested at an oil production well site in Michigan. It was determined that the compound quickly broke a very dense o/w emulsion and reduced oil levels in injection water from approx. 280 ppm (as determined by Wilks IR analyzer) to levels as low as 20 ppm.

USE AS A CORROSION INHIBITOR

This aspect of the present invention relates to the use of the compounds according to the invention to inhibit corrosion on metals, especially iron, steel and ferroalloys. The compounds can be used in many different applications and systems where iron, steel and ferroalloys are affected by corrosion. They can be used to inhibit corrosion in processes that require a protective or passivating coating, such as by dissolution in the medium that comes into contact with the metal. They can be used to prevent atmospheric corrosion, underwater corrosion, corrosion in steam and hot water systems, corrosion in chemical industries, underground corrosion and the like.

The corrosion inhibitors contemplated herein find particular use in the prevention of corrosion on pipes or equipment that are in contact with a corrosive oil-containing medium, such as for example in oil wells that produce corrosive oil or oil-salt solution mixtures, in refineries and the like . However, these inhibitors can be used in other systems or applications. They turn out to have properties that give metals resistance to attack by many different corrosive substances, such as salt solutions, weak inorganic acids, organic acids, C02, H2S and the like.

The procedure for using the compounds is relatively simple in principle. The corrosion-preventing compound dissolves in the liquid corrosive medium in small quantities and is thus kept in contact with the metal surface to be protected. Alternatively, the corrosion inhibitor can first be applied to the metal surface either as it is or as a solution in some carrier liquid or paste. Continuous feeding, as in solution, is the preferred method.

A method for using the compounds according to the invention finds particular use in the protection of metal equipment for oil and gas wells, especially those which contain or produce an acidic component such as H2S, C02 » organic acids and the like. To protect such wells, the compound, either undiluted or dissolved in a suitable solvent, is led down the well annulus between the well pipe and the production pipe system where it is mixed with the fluid in the well and pumped or allowed to flow from the well together with these fluids, thus coming into contact with the inner wall of the well pipe, the outer and inner wall of the piping system, and the inner surface of all wellhead accessories, couplings and flow lines where the corrosive fluid is handled.

When the inhibitor compound is a liquid, it is conventionally directed down the well annulus by means of a motor-driven chemical injection pump, or it can be periodically (eg once every day or every other) dropped into the annulus by means of a so-called " boll weevil" device or similar arrangement. When the inhibitor compound is in solid form, it can be dropped into the well as a solid lump or rod, it can be blown in as a powder with gas, or it can be washed in with a small stream of the well fluids or other liquid. Where there is gas pressure on the well pipe, it is of course necessary to apply all these treatment methods through a pressure equalization chamber which is equipped for the introduction of reagent into the chamber, equalization of pressure between chamber and well pipe and movement of reagent from the chamber to the well pipe.

Oil and gas wells are occasionally completed in such a way that there is no opening between the annulus and the bottom of the piping or pump. This happens, for example, when the pipe system is at one point or another surrounded by a filling mass that is held by the well pipe or the soil formation below the well pipe. In such wells, the compounds can be introduced into the pipe system through a pressure equalization container, after stopping the flow of fluids. After the well has been treated in this way, it should be allowed to remain closed for a period of time sufficient for the compound to fall to the bottom of the well.

For injection into the well ring, the corrosion inhibitor is usually used as a solution in a suitable solvent. The choice of solvent will depend on the specific compound used and its dissolution properties.

For the treatment of wells with a "packed off" piping system, the use of fixed "rods" or plugs of a preparation containing the inhibitor is particularly suitable. These can be produced by mixing the inhibitor with a mineral wax, asphalt or resin in a ratio that is sufficient to obtain a moderately hard and high-melting solid that can be processed and conveniently fed into the well.

The protective effect of the compounds described herein is shown to persist for a substantial period of time after treatment is discontinued, but is eventually lost if no further administration is made.

For the protection of gas wells and gas-condensate wells, the amount of corrosion inhibitor required will be in the range of 8-48 g per million dm<3>of gas produced, depending on the amounts and composition of corrosive substances in the gas and the amount of liquid hydrocarbon and water formed. In no case does it appear that the amount of inhibitor required is stoichiometrically related to the amount of acids formed in a well, since protection is achieved with much less corrosion inhibitor than would normally be required to neutralize the acids formed.

The compounds are particularly effective in preventing corrosion in systems containing a corrosive aqueous medium, and especially in systems containing salt solutions.

The compounds can also be used to prevent corrosion during the secondary extraction of petroleum by waterflooding and when removing waste water and brine from oil and gas wells. Even more particularly, they can be used in a method for preventing corrosion by waterflooding and by removing waste water and brine from oil and gas wells, which is characterized by being injected into an underground formation as an aqueous solution containing less but

effective amounts of the compounds of this invention,

for the prevention of corrosion of metals used in such an operation.

When an oil well naturally stops flowing

pressure in the formation and/or significant quantities of oil can no longer be obtained by the usual pumping methods, different methods are sometimes used for treating the oil-bearing formation in order to increase the oil flow. These methods are usually described as secondary recovery methods. One such method that is very commonly used is the waterflooding method where water is pumped under pressure into what is called an "injection well" and oil, along with the amount of water that has been displaced from the formation, is pumped out of an adjacent well which usually referred to as a "producing well". The oil that is pumped from the producing well is then separated from the water that has been pumped from the producing well, and the water is pumped to a storage reservoir from which it can again be pumped into the injection well. Additional water from other sources can also be used in connection with the water formed. When the storage reservoir is open to the atmosphere and the oil is exposed to aeration, this water flooding system type is referred to herein as "open water flooding system". If the water is recirculated in a closed system without any significant aeration, the secondary recovery process is referred to herein as a "closed water flooding system".

Due to the corrosive nature of oil field brines, it is necessary to prevent or reduce corrosion,

since corrosion increases costs by requiring the repair and replacement of such equipment at frequent intervals.

Application of the compounds according to the invention protects metallic equipment used in secondary oil extraction by waterflooding such as injection wells, transmission lines, filters, measuring devices, storage tanks and other metallic tools used for this and especially those containing iron, steel and ferroalloys, against corrosion.

In many fields, large volumes of water are formed that must be removed where waterflooding operations are not in use or where waterflooding operations cannot handle the amount of water formed. Many countries have laws that limit the pollution of streams and land areas with produced bodies of water, and oil producers must then find a method for removing the formed waste salt water. In many cases, the salt water is disposed of by injecting the water into permeable low-pressure layers below the fresh water level. The formation into which the water is injected is not the oil-producing formation, and this type of removal is defined as saltwater removal or waste water removal. The problems with corrosion of equipment are analogous to those encountered in the secondary recovery operation by waterflooding.

The compounds according to this invention can also be used in such water removal wells, as a simple and economical method is thus provided to solve the corrosion problems encountered when removing unwanted water.

Waterflooding and waste removal operations are too well known to need further elaboration. According to the present invention, the flushing operation is actually carried out in a conventional manner, except that the flushing medium contains a smaller amount of the compounds according to the invention, sufficient to prevent corrosion.

While the flotation medium used according to the present invention contains water or oil field brine and the compounds according to this invention, the medium may also contain other materials. For example, the flooding medium can also contain other substances such as surface-active substances or detergents that help with wetting and also support the desorption of residual oil from the formation, sequestering agents that prevent the deposition of calcium and/or magnesium compounds in the spaces in the formation, bactericides that prevent the formation becomes clogged by bacterial growth, indicators ("tracers") and the like.

The application concentration of the corrosion inhibitors according to this invention will vary to a great extent depending on the specific compound used, the design of it with other materials, the particular system and the like. Concentrations of at least approx. 5 ppm, such as from approx. 10 to approx. 10,000 ppm, for example from approx. 25 to approx. 5,000 ppm, beneficial from approx. 25 to approx. 1,000 ppm, preferably from approx. 25 to approx. 250 ppm can be used. Larger amounts can also be used. Since the favorable result of a waterflooding operation obviously depends on its total cost being less than the value of the additional oil extracted from the oil reservoir, it is, for example, absolutely essential to use as little of these compounds as possible which can be combined with optimal corrosion inhibition. Since the compounds themselves are cheap and are used in low concentrations, they increase the favorable result of a flotation operation by lowering the costs thereof.

By varying the components of the preparation containing the compounds according to the invention, the compounds can be made more oil- or water-soluble, depending on whether the preparation is to be used in oil or water systems.

All the compounds presented and described herein are used as corrosion inhibitors. Preferably, however, the compounds according to formula (A)-(C) are used in this way since they are particularly effective as corrosion inhibitors.

Example 14

TEST FOR "SWEET" CORROSIVE SYSTEMS

C02 saline shower test

The C02 saline shower test is a reliable, rapid

test to investigate compounds as corrosion inhibitors in "sweet" corrosive systems. A laboratory salt solution is showered with stirring with 99.9% pure C02i approx. 1 hour before immersion of cleaned and weighed corrosion test pieces. An M-1010 "Pair" meter was used to control the corrosion rate in each test cell. After 1-2 hours the corrosion rate reached an "equilibrium", but a pre-corrosion period of 3.5 hours was used to obtain consistency before the experimental inhibitor was added. The pre-corrosion period in the inhibited salt solution is very important. This provides a pre-corroded test surface whereby surface preparation variations are minimized and at least a minimal corrosion product layer is provided where there is no inhibitor and against which the test inhibitor must work. This step is important because the inhibitor is only rarely used in the equipment from

day 1, and then it is used on rusted steel and not recently sandblasted surfaces.

The inhibitors were injected below the saline solution surface at 50 ppm based on the active ingredient. The test period of 24 hours was checked with an M-1010 PAIR meter as a "back-up", but the corrosion rates and percentage protection were determined by weight loss measurements.

Examples of sweet corrosive systems include carbon dioxide-containing gas systems such as sweet gas lines, sweet gas wells and similar systems.

The test results are summarized in the following table:

The results clearly show the effectiveness of the compounds according to the invention as corrosion inhibitors. These compounds also have the following very important properties: 1) They have excellent stability in fresh water and salt solutions of high concentration.

2) They are non-emulsifying.

3) They show extremely rapid corrosion inhibition.

USE AS SCALE INHIBITORS

This aspect of the invention relates to the use of the components according to the invention to inhibit shell formation in many different applications and systems.

Scale formation in aqueous solutions containing an oxide variety of scale-forming compounds, such as calcium, barium and magnesium carbonates, sulphates, silicates, oxalates, phosphates, hydroxides, fluorides and the like, is inhibited by the use of threshold amounts of the compounds according to the invention, such as less than 2.5 ppm.

The shell inhibitors according to the present invention illustrate improved inhibitory effect at high temperatures compared to compounds according to the state of the art. The compounds according to the present invention will inhibit the deposition of shell-forming alkaline earth metal compounds on a surface that is in contact with an aqueous solution of the alkaline earth metal compounds over a wide temperature range. Usually the temperatures in the aqueous solution will be at least 45°C, although considerably lower temperatures will often be encountered.

The preferred temperature range for inhibiting shell deposition is from approx. 34 to 175°C. The aqueous solutions or salt solutions that need treatment usually contain from approx. 50 to approx. 50,000 ppm of shell-forming salts. The compounds according to the present invention effectively inhibit shell formation when present in an amount of from approx. 0.1 to approx. 100 ppm, preferably from approx. 0.2 to approx. 50 ppm, where the amounts of the inhibitor are based on the total aqueous system. There appears to be no concentration below which the compounds of the present invention are completely ineffective. A very small amount of the shell inhibitor is effective to a correspondingly limited extent, and the threshold effect is achieved with less than 0.1 ppm. There is no reason to believe that this is the minimum effective concentration. The shell inhibitors according to the present invention are effective both in salt solution, such as seawater, and acid solutions.

The following test is used for the evaluation of compounds as shell inhibitors.

1. Make a stock solution of CaCl^I^O, 2.94 g/l.

2. The NaHCO3 stock solution should be 3.35 g/l.

3. Inhibitors - Make 0.1% solutions in deionized water. 1 ml in 100 ml sample = 10 ppm (Test with 5, 20 and 50 ppm) .

Fill 50 ml bicarbonate solution in 100 ml milk dilution bottle. Add inhibitor (for a final volume of 100 mL). Then add 50 ml of CaCl2 solution and place it in a bath at 82°C. Do not put a cap on. Always make a blank test. Run a hardness determination on a 50/50 mixture before heating.

Heat to 82°C. Take 10 ml samples from bottles after 2 and 4 hours.

Filter through millipore filter.

Run a total hardness determination on the filtrate.

Calculate as % Ca still in solution, i.e.

All the compounds presented and described herein are used as shell inhibitors. Preferably, however, the compounds according to the formulas (A)-(C) are used in this way since they are particularly effective as shell inhibitors.

WATER CLEARANCE

This aspect of the present invention relates to the use of the compounds according to the invention for the clarification of water containing divalent iron ions and suspended material.

Water containing divalent iron ions and suspended particles that can be treated with the compounds of the present invention may originate in either natural or artificial sources, including industrial and sanitary sources. Water containing suspended particles of natural origin is usually surface water where the particles are suspended soil particles (sludge), although water below the surface can also be treated according to the present invention. Water originating in industrial process (including sanitary water) operations can contain many different types of suspended particles. These particles are usually the result of the particular industrial or sanitary operation in question. Before discharging such industrial waste water into natural watercourses, it is usually desired, or required, that the suspended material be removed.

The present invention can likewise be used for water found in stock or fish ponds, lakes or other natural or artificial bodies of water containing suspended solids. The compounds can be added to industrial water supplies either during preparation ("in preparation therefor"), during or after use and before removal. The compounds can be added to sanitary water supplies, either for the disposal of suspended solids before use or they can be added to water that has been contaminated with impurities from one source or another.

Most naturally occurring water contains an amount of simple electrolytes (sodium, potassium, ammonium, calcium, aluminum salts) in excess of what is necessary for the initial aggregation of the final sludge particles. This is also the case when it comes to particles of suspended material in industrial or sanitary water. The final particles in sludge or other materials are therefore naturally aggregated partly due to the presence of such electrolytes. However, the forces that bind together such final particles are not great and are not such that they generally cause either rapid sedimentation rates for the flocculated material, or strong enough to prevent deflocculation.

The compounds according to this invention cause rapid flocculation and also strengthen the formed aggregates of particles, as they cause a general densification or bonding of the initial particles and an increasing rate of coagulation and sedimentation, thus forming a less cloudy supernatant liquid.

Addition of the compounds according to this invention to the water suspension should be done in such a way that the resulting flocculation and aggregation of the particles takes place uniformly throughout the entire water mass. To achieve a uniform addition of the compounds according to the invention to the water-borne suspension, it is usually desirable to prepare a relatively diluted stock solution of the compound and then add such a solution to the water mass. Clarification can take place either in the natural body of water or it can be caused to take place in hydraulic thickening devices of known design.

The amount of the compounds according to the invention used will vary depending on the amount and degree of subdivision of the solids to be agglomerated or flocculated, the chemical nature of such a solid and the particular compound used. Usually, at least a sufficient amount of the compound is used to support flocculation; usually from approx. 0.005 to approx. 10,000 ppm or more, such as from approx. 0.5 to approx. 1,000 ppm, for example from approx. 1 to approx. 500 ppm, preferably from approx. 2 to approx. 5 ppm. Since the economy of these methods is important, usually no more than the minimum amount required for effective removal is used. It is of course desirable to use a sufficient amount of the compound so that flocculation will take place without causing the formation of stable dispersions.

The precipitating effect of the compounds according to the invention can be used when applying loading or filling materials to textiles or paper.

The compounds according to the invention will be particularly suitable for processing fine mineral particles in aqueous suspension. When processing ore to separate valuable mineral constituents from unwanted matrix constituents, it is common practice to grind the ore to a finely divided state to facilitate the separation steps such as selective flotation and the like. In many ore dressing processes, the finely divided ore is suspended in water to form a mass or slurry. After processing, it is usually desirable to dewater the mass or sludge either by sedimentation or filtration. In such operations, some ores are particularly difficult, since the finely divided ore forms a stable slurry when suspended in water, which settles very slowly, if at all. Such sludge is unsuitable for concentration or dewatering by sedimentation and is difficult to dewater by filtration due to the tendency to clog the filter's press, thus leading to unreasonably time-consuming and inefficient operation of the filters. In some cases, for example in certain phosphate mining operations, the formation of very stable suspensions of finely divided mineral not only results in the loss of considerable valuable mineral as waste, but also requires large expenses for the maintenance of storage basins for the waste. Similar problems arise when processing gold, copper, nickel, lead, zinc, iron, taconite ores, uranium and other ores.

Some specific additional uses for the compounds of the invention which are not intended to be limiting, but merely illustrative, are listed below. The compounds can be used to clarify beer or wine during production. Another application is for the treatment of effluent streams in pharmaceutical operations for the recovery of valuable products or the removal of unwanted by-products. A particularly important application is for the clarification of both beet sugar and cane sugar juice when processing these. Yet another application is for flocculation and extraction of pigments from aqueous suspensions thereof. The compounds will be particularly suitable in sewage treatment operations as flocculants. A further application is by flocculation to support the removal of coal from aqueous suspensions thereof. The preparations can also be used in the process for flocculating tailwater and/or recirculating the precipitated solids in the papermaking process described in US patent no. 3,393,157, and other processes described therein. In other words, the compounds according to the invention are generally suitable for treating aqueous effluent streams of all types to facilitate the removal of suspended solids.

Naturally occurring water from many sources, and in some cases salt solutions and brackish water, is used in the extraction of petroleum in secondary waterflooding operations. Clarification of the water is necessary in many cases before flooding because the suspended pollutants tend to clog the underground formations into which the water masses are pumped.

Example 15

A suspension of FeS in salt solution is exposed to the action of the water-soluble polymers prepared herein.

In this experiment, the FeS concentration is 25 parts per million and 1% and 5% saline solutions are used. Measured quantities (500 ml) of the homogeneous suspension are placed in a 1000 ml beaker and stirred at 100 rpm (revolutions per minute). The compound to be tested is injected into the suspension, resulting in active final concentrations that vary between 2 and 4 parts per million. A commercial flocculant is run concurrently at similar concentrations for comparison, and agitation is achieved using a Phipp and Bird type "flock" multi-agitator. After one minute, the stirring speed is reduced to 20-30 rpm and kept this way for 10 minutes. At this point, the stirring is stopped. The evaluation of the polymer starts at the moment of flocculation and continues with respect to the "floc" size and the rate of precipitation. The final assessment is obtained by examining the color of the resulting aqueous phase.

The results obtained by using the compounds according to this invention have been found to be superior to commonly used flocculating agents.

All the compounds presented and described herein are used as flocculating agents and flotation aids. Preferably, however, the compounds according to formula (A)-(C) are used in this way since they are particularly effective as flotation aids and flocculation agents.

USE AS BACTERIAL INHIBITORS

This aspect of the invention relates to the secondary extraction of oil by waterflooding operations and more particularly relates to an improved method for treating saltflood water and oil extraction therefrom. More particularly, this invention relates to a method for inhibiting bacterial growth by extracting oil from oil-bearing layers by means of waterflooding which takes place in the presence of sulphate-reducing bacteria.

Waterflooding is used to a large extent in the petroleum industry to effect secondary extraction of oil. By using this method, the yield of oil from a given field can be increased beyond the 20-30% of the oil in a producing formation that is usually extracted by the primary process. In a flooding operation, water is forced under pressure through injection wells into or under oil-bearing formations while displacing the oil from these to adjacent producing wells. The oil-water mixture is usually pumped from the producing wells into a receiving tank where the water, separated from the oil, is led away using a siphon, and then the oil is transferred to storage tanks. It is desirable when carrying out this method to maintain a high water injection rate with a minimal consumption of energy. Any obstacle to the free access of the water in oil-bearing formations seriously reduces the efficiency of the extraction operation.

Particularly difficult and common to all types of water are problems that are directly or indirectly caused by the presence of microorganisms, such as bacteria, fungi and algae. Microorganisms can prevent the free access of water in oil-bearing formations by forming ions capable of forming scum and sludge, and/or they can be present in sufficiently high numbers to form a significant mass, thereby plugging the pores of the oil-bearing formation. Free-plugging increases the pressure required to drive a given volume of water into an oil-bearing formation and often causes the flooding water to bypass the formation to be filled with water. Furthermore, microorganisms can cause corrosion by acting on the metal structures in the wells in question, forming corrosive substances such as hydrogen sulphide, or by producing conditions that are favorable for decomposing corrosion such as a reduction in pH or the formation of oxygen. The products that form as a result of corrosive action can also be pore-clogging impurities. Usually the difficulties encountered are a combination of effects resulting from the activity of various microorganisms, such as aerobic and anaerobic bacteria, including sulfate-reducing bacteria.

Example 16

The compound of Example 4 was tested for efficacy using a standard laboratory test method. The compounds were tested against a mixed culture of aerobic and anaerobic bacteria, including sulfate-reducing bacteria.

The experimental medium consisted of aged artificial seawater with 0.1 g/litre nutrient broth added. The medium was purged with nitrogen to remove oxygen, and inoculated with 10 ml/liter of a mixed culture of aerobic and anaerobic bacteria from oil field water. Aliquots (50 ml) were dispensed into sterile, nitrogen-filled serum vials. Concentrations of the test compounds were prepared by adding the appropriate amount of a 5% solution of the compound to 50 ml of test medium. After 24 hours, exposure levels for aerobic, anaerobic and sulfate-reducing bacteria were counted.

The results are shown in Table 3 below:

It should be clear that compounds analogous to those described and exemplified herein may be used in the present invention. Thus, compounds where -SR7 can be substituted by -OR7 and -NR7 are also intended to be within the scope of this invention.

It should also be clear that the compounds according to the invention can be designed with other materials that are suitable in the fields to which the invention applies; thus, the compounds can be dispersed or dissolved in suitable diluents and solvents and can be used together with surfactants and other chemical treatment agents suitable for the same or other purposes, e.g. corrosion inhibitors, demulsifiers, scale and bacteria inhibitors, flocculation agents, water clarification agents and the like.

Although the illustrative embodiments of the invention have been described in detail, it will be understood that various other modifications will be obvious to, and can be easily carried out by, those skilled in the art without deviating from the principle and scope of the invention. Consequently, it is not intended that the scope of the claims linked hereto shall be limited to the examples and descriptions given herein, but rather the claims shall be understood to encompass all the patentable novelty features found in the present invention, including all the features that would be treated as equivalent to these by those skilled in the art in the field to which the invention applies.

Claims (21)

1. Compound, characterized by the formula where R represents an organic group, R 1 and R 2 each represent an organic group, R 3 and R 6 each represent H or an organic group, R7 represents a cation, R 8 represents H, OH or -N(R 3 )C(=S)SR 7 , where R4 and R5 each repeat centers H or an organic group, R10 represents H or an organic group, m and m^ each represent 0 or 1-500, x and x^ each represent 0 or at least 1 and Yl f <y>2 and y3 each represent at least 1, the sum of <Y>1<+y>2<+y> 3 <g> average is equal to 3-250. 2. Compound, characterized by the formula where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl,R;L represents lower alkylene, R3 represents H or lower alkyl, R7 represents H or an alkali metal, R8 represents -N(R3 )C(=S)SR7 , where R4 and R5 each represent centers H or -C(=S)SR7 , R10 represents hydrogen or an organic group and Yl> <y>2 °9 <y>3 nver represents at least 1. 3. Compound according to claim 2, characterized by the formula where Yl»<y>2 °9 <y>3 nver represents at least 1, since the sum of <y> 1 <+y>2<+y>3<g> on average equals from 3 to approx. 6. 4. Compound according to claim 1, characterized by the formula where R represents alkanetetrayl, cycloalkanetetrayl or alkylsub substituted aromatic tetrayl, R 1 and R 2 each represent lower alkylene, R 3 represents H, lower alkyl or aryl, R 6 represents H or -C(=S)SR 7 , R7 represents an alkali metal, R 8 represents -N(R 3 )C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , R10 represents H or an organic group, m and row. 1 each represents 1 and Yl' Y2 0 <<> 3 Y3 nver represents at least1 . 5. Compound, characterized by the formula where <*> R represents an organic group, R 1 and R 2 each represent an organic group, R3 and R6 each represent H or an organic group, R7 represents a cation, R 8 represents H, -OH or -N(R 3 )C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , Ri g represents H or an organic group, m and m^ each represent 0 or 1-500, x and x! each represents 0 or at least 1 and Yl' Y2 °9 Y3 each represents at least 1, the sum of Yl<+> Y2 +Y3 average is equal to 3-250. 6. Compound according to claim 5, characterized by the formula where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl, R-L and R2 each represent lower alkylene, R 3 represents H, R 6 represents H or -C(=S)SR 7 , R7 represents an alkali metal, R 8 represents -N(H)C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , R10 represents H or an organic group, m and v\ in each represent 1 and Yl » Y2 0 <<> ? Y3 nver represents at least1 . 7. Compound, characterized by the formula where R represents an organic group, R 1 and R 2 each represent an organic group, R3 and R6 each represent H or an organic group, R7 represents a cation, R 8 represents H, -OH or -N(R 3 )C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or an organic group, R10 represents H or an organic group, m and rai each represent 0 or 1-500, x and x1 each represent 0 or at least 1 and Yl » Y2 0<3 Y3 each represent at least 1, the sum of <Y>l<+> Y2 <+> Y3 <g> average is equal to 3-250. 8. Compound according to claim 7, characterized by the formula where R represents alkanetetrayl, cycloalkanetetrayl or aromatic tetrayl, R 1 and R 2 each represent lower alkylene, R 3 represents H, R 6 represents H or -C(=S)SR 7 , R7 represents an alkali metal, R 8 represents -N(H)C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , R10 represents H or an organic group, m and mi each represent 1 and Yl' Y2 0<3 Y3 each represents at least l. 9. Compound, characterized by the formula 10. Compound, characterized by the formula 11. Method for demulsifying a reverse emulsion, characterized by adding to this an effective demulsifying amount of a preparation comprising a compound according to the formula where R represents alkanetetrayl, cycloalkanetetrayl, aromatic tetrayl or -R]_ Rn represents the alkylene Ride-, R3 represents H, lower alkyl, benzyl or -C(=S)SR7 , R7 represents Na, K, Ca or NH4 , R 8 represents H or -N(R 3 )C(=S)SR 7 , Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , R 10 represents H or an organic group and R and R 3 , together with their common nitrogen atom, can represent a ring structure. 12. Method for demulsifying a reverse emulsion, characterized by adding to this an effective demulsifying quantity of a preparation comprising a compound with the formula where R represents alkanetriyl, cycloalkanetriyl or aromatic triyl, R 2 represents lower alkylene or arylene, R 3 represents H, lower alkyl or aryl, R6 represents H, -C(=S)SR7 or -R2 -N(H)C(=S)SNa, R7 represents Na, K, Ca or NH4, Rg represents where R4 and R5 each repeat centers H or -C(=S)SR7 , Rio represents H or an organic group and m represents 1-3. 13. Method for demulsifying a reverse emulsion, characterized in that an effective emulsifying amount of a preparation comprising a compound according to claims 1-10 is added to the emulsion. 14. Method for inhibiting corrosion of metals in a system, characterized in that an effective inhibitory amount of a compound according to claims 1, 2, 5, 7, 9 and 10 is added to the system. 15. Method for deflocculating a system, characterized in that an effective flocculating amount of a compound according to claims 1, 3, 5, 7, 9 and 10 is added to the system. 16. Method for inhibiting bacterial growth in a system, characterized in that an effective biocidal amount of a compound according to claims 1 is added to the system, 3, 5, 7, 9 and 10. 17. Method for supporting the flotation of solids in a system, characterized in that an effective amount of a compound according to claims 1, 3, 5, 7, 9 and 10 is added to the system. 18. Process for clarifying water, characterized in that an effective clarifying amount of a compound according to claims 1, 3, 5, 7, 9 and 10 is added to the water. 19. Method for interface regulation of a system, characterized in that an effective amount of a compound according to claims 1, 3, 5, 7, 9 and 10 is added to the system. 20. Method for inhibiting foaming in a system, characterized in that an effective foam-inhibiting amount of a compound according to claims 1, 3, 5, 7, 9 and 10 is added to the system. 21. Preparation, characterized in that it comprises a compound according to claims 1, 5 and 7, and a diluent for this.