Title of Invention	A NOVEL ADDITIVE FOR NAPHTHENIC ACID CORROSION INHIBITION AND METHOD OF USING THE SAME
Abstract	The present invention relates to the field of processing hydrocarbons which cause corrosion in the metal surfaces of processing units. The invention addresses the technical problem of high temperature naphthenic acid corrosion and sulphur corrosion and provide solution to inhibits these type of corrosions. The three combination compositions are formed by two mixtures separately,one mixture obtained by mixing a compound A, which is obtained by reacting high reactive polyisobutylene (HRPIB) with phosphorous pentasulphide in presence of catlytic amount of sulphur with compund B which is thiophosphorous compound such as phosphorous thioacid ester of formula 1 and second mixture obtained by mixing compound a with compound C of formula 2 which is obtained by reacting compound B with ethylene oxide, wherein each of these two mixtures independently provide high corrosion inhibition efficiency in case of high temperature naphthenic acid corrosion inhibition. The invention is useful in all hydrocarbon processing units, such as refineries, distillation columns and other petrochemical industries.

Title of Invention

A NOVEL ADDITIVE FOR NAPHTHENIC ACID CORROSION INHIBITION AND METHOD OF USING THE SAME

Abstract

The present invention relates to the field of processing hydrocarbons which cause corrosion in the metal surfaces of processing units. The invention addresses the technical problem of high temperature naphthenic acid corrosion and sulphur corrosion and provide solution to inhibits these type of corrosions. The three combination compositions are formed by two mixtures separately,one mixture obtained by mixing a compound A, which is obtained by reacting high reactive polyisobutylene (HRPIB) with phosphorous pentasulphide in presence of catlytic amount of sulphur with compund B which is thiophosphorous compound such as phosphorous thioacid ester of formula 1 and second mixture obtained by mixing compound a with compound C of formula 2 which is obtained by reacting compound B with ethylene oxide, wherein each of these two mixtures independently provide high corrosion inhibition efficiency in case of high temperature naphthenic acid corrosion inhibition. The invention is useful in all hydrocarbon processing units, such as refineries, distillation columns and other petrochemical industries.

Full Text	FORM 2 THE PATENTS ACT 1970 (39 of 1970) & The Patent Rules, 2003 Provisional Specification (See section 10 and rule 13) A novel additive for naphthenic acid corrosion inhibition and method of using the same. Dorf Ketal Chemicals (I) Pvt. Ltd Dorf Ketal Tower, D'monte Street, Orlem, Malad (W), Mumbai, 400064 Maharashtra State, India. An Indian company registered under the Companies Act, 1956 The following specification describes the invention: A NOVEL ADDITIVE FOR NAPHTHENIC ACID CORROSION INHIBITION AND METHOD OF USING THE SAME. FIELD OF THE INVENTION The present invention relates to the inhibition of metal corrosion in acidic hot hydrocarbons and more particularly to he inhibition of corrosion of iron -containing metals in hot acidic hydrocarbons, especially when the acidity is derived from the presence of naphthenic acid. DISCUSSION OF PRIOR ART It is widely known in the art that the processing of crude oil and its various fractions has led to damage to piping and other associated equipment due to naphthenic acid corrosion. These are corrosive to the equipment used to distill, extract, transport and process the crudes. Generally speaking, naphthenic acid corrosion occurs when the crude being processed has a neutralization number or total acid number (TAN), expressed as the milligrams of potassium hydroxide required to neutralize the acids in a one gram sample, above 0.2. It is also known that naphthenic acid-containing hydrocarbon is at a temperature between about 200.degree. C. and 400.degree. C. (approximately 400.degree. F.-750.degree. F.), and also when fluid velocities are high or liquid impinges on process surfaces e.g. in transfer lines, return bends and restricted flow areas. Corrosion problems in petroleum refining operations associated with naphthenic acid constituents and sulfur compounds in crude oils have been recognized for many years. Such corrosion is particularly severe in atmospheric and vacuum distillation units at temperatures between 400.degree. F. and 790.degree. F. Other factors that contribute to the corrosivity of crudes containing naphthenic acids include the amount of naphthenic acid present, the concentration of sulfur 2 compounds, the velocity and turbulence of the flow stream in the units, and the location in the unit (e.g., liquid/vapor interface). As commonly used, naphthenic acid is a collective term for certain organic acids present in various crude oils. Although there may be present minor amounts of other organic acids, it is understood that the majority of the acids in naphthenic based crude are naphthenic in character, i.e., with a saturated ring structure as follows: The molecular weight of naphthenic acid can extend over a large range. However, the majority of the naphthenic acid from crude oils is found in gas oil and light lubricating oil. 15 When hydrocarbons containing such naphthenic acid contact iron-containing metals, especially at elevated temperatures, severe corrosion problems arise. Naphthenic acid corrosion has plagued the refining industry for many years. This corroding material consists of predominantly monocyclic or bicyclic carboxylic acids with a boiling range between 350.degree. and 650.degree. F. These acids tend to concentrate in the heavier fractions during crude distillation. Thus, locations such as the furnace tubing, transfer lines, fractionating tower internals, feed and reflux sections of columns, heat exchangers, tray bottoms and condensers are primary sites of attack for naphthenic acid. Additionally, when crude stocks high in naphthenic acids are processed, severe corrosion can occur in the carbon steel or ferritic steel furnace tubes and tower bottoms. Recently interest has grown in the control of this type of corrosion in hydrocarbon processing units due to the presence of naphthenic acid in crudes from locations such as China, India, Africa and Europe. 3 Crude oils are hydrocarbon mixtures which have a range of molecular structures and consequent range of physical properties. The physical properties of naphthenic acids which may be contained in the hydrocarbon mixtures also vary with the changes in molecular weight, as well as the source of oil containing the acid. Therefore, characterization and behavior of these acids are not well understood. A well known method used to "quantify" the acid concentration in crude oil has been a KOH titration of the oil. The oil is titrated with KOH, a strong base, to an end point which assures that all acids in the sample have been neutralized. The unit of this titration is mg. of KOH/gram of sample and is referred to as the "Total Acid Number" (TAN) or Neutralization Number. Both terms are used interchangeably in the application. The unit of TAN is commonly used since it is not possible to calculate the acidity of the oil in terms of moles of acid, or any other of the usual analytical terms for acid content. Refiners have used TAN as a general guideline for predicting naphthenic acid corrosion. For example, many refineries blend their crude to a TAN=0.5 assuming that at these concentrations naphthenic acid corrosion will not occur. However, this measure has been unsuccessful in preventing corrosion by naphthenic acid. Naphthenic acid corrosion is very temperature dependent. The generally accepted temperature range for this corrosion is between 205.degree. C. and 400.degree. C. (400.degree. F. and 750.degree. F.). Corrosion attack by these acids below 205.degree. C. has not yet been reported in the published literature. As to the upper boundary, data suggests that corrosion rates reach a maximum at about 600.degree.-700.degree. F. and then begin to diminish. The concentration and velocity of the acid/oil mixture are also important factors which influence naphthenic acid corrosion. This is evidenced by the appearance of 4 the surfaces affected by naphthenic acid corrosion. The manner of corrosion can be deduced from the patterns and color variations in the corroded surfaces. Under some conditions, the metal surface is uniformly thinned. Thinned areas also occur when condensed acid runs down the wall of a vessel. Alternatively, in the presence of naphthenic acid pitting occurs, often in piping or at welds. Usually the metal outside the pit is covered with a heavy, black sulfide film, while the surface of the pit is bright metal or has only a thin, grey to black film covering it. Moreover, another pattern of corrosion is erosion-corrosion, which has a characteristic pattern of gouges with sharp edges. The surface appears clean, with no visible by-products. The pattern of metal corrosion is indicative of the fluid flow within the system, since increased contact with surfaces allows for a greater amount of corrosion to- take place. Therefore, corrosion patterns provide information as to the method of corrosion which has taken place. Also, the more complex the corrosion, i.e., in increasing complexity from uniform to pitting to erosion-corrosion, the lower is the TAN value which triggers the behavior. The information provided by corrosion patterns indicates whether naphthenic acid is the corroding agent, or rather if the process of corrosion occurs as a result of attack by sulfur. Most crude contain hydrogen sulfide, and therefore readily form iron sulfide films on carbon steel. In all cases that have been observed in the laboratory or in the field, metal surfaces have been covered with a film of some sort. In the presence of hydrogen sulfide the film formed is invariably iron sulfide, while in the few cases where tests have been run in sulfur free conditions, the metal is covered with iron oxide, as there is always enough water or oxygen present to produce a thin film on the metal coupons. Tests utilized to determine the extent of corrosion may also serve as indicators of the type of corrosion occurring within a particular hydrocarbon treating unit. Metal coupons can be inserted into the system. As they are corroded, they lose material. This weight loss is recorded in units of mg/cm.sup.2. Thereafter, the 5 corrosion rate can be determined from weight loss measurements. Then the ratio of corrosion rate to corrosion product (mpy/mg/cm.sup.2) is calculated. This is a further indicator of the type of corrosion process which has taken place, for if this ratio is less than 10, it has been found that there is little or no contribution of naphthenic acid to the corrosion process. However, if the ratio exceeds 10, then naphthenic acid is a significant contributor to the corrosion process. Distinguishing between sulfidation attack and corrosion caused by naphthenic acid is important, since different remedies are required depending upon the corroding agent. Usually, retardation of corrosion caused by sulfur compounds at elevated temperatures is effected by increasing the amount of chromium in the alloy which is used in the hydrocarbon treating unit. A range of alloys may be employed, from 1.25% Cr to 12% Cr, or perhaps even higher. Unfortunately, these show little to no resistance to naphthenic acid. To compensate for the corroding effects of sulfur and naphthenic acid, an austenitic stainless steel which contains at least 2.5% molybdenum, must be utilized. The corrosive problem is known to be aggravated by the elevated temperatures necessary to refine and crack the oil and by the oil's acidity which is caused primarily by high levels of naphthenic acid indigenous to the crudes.Naphthenic acids is corrosive between the range of about 175 degree C to 420.degree. C. At the higher temperatures the naphthenic acids are in the vapor phase and at the lower temperatures the corrosion rate is not serious. The corrosivity of naphthenic acids appears to be exceptionally serious in the presence of sulfide compounds, such as hydrogen sulfide, mercaptans, elemental sulfur, sulfides, disulfides, polysulfides and thiophenols. Corrosion due to sulfur compounds becomes significant at temperatures as low as 450.degree. F. The catalytic generation of hydrogen sulfide by thermal decomposition of mercaptans has been identified as a cause of sulfidic corrosion. 6 Sulfur in the crudes, which produces hydrogen sulfide at higher temperatures, also aggravates the problem. The temperature range of primary interest for this type of corrosion is in the range of about 175.degree. C. to about 400.degree. C, especially about 205.degree. C. to about 400.degree. C. Various approaches to controlling naphthenic acid corrosion have included neutralization and/or removal of naphthenic acids from the crude being processed; blending low acid number oils with corrosive high acid number oils to reduce the overall neutralization number; and the use of relatively expensive corrosion-resistant alloys in the construction of the piping and associated equipment. These attempts are generally disadvantageous in that they require additional processing and/or add substantial costs to treatment of the crude oil. Alternatively, various amine and amide based corrosion inhibitors are commercially available, but these are generally ineffective in the high temperature environment of naphthenic acid corrosion. Naphthenic acid corrosion is readily distinguished from conventional fouling problems such as coking and polymer deposition which can occur in ethylene cracking and other hydrocarbon processing reactions using petroleum based feedstocks. Naphthenic acid corrosion produces a characteristic grooving of the metal in contact with the corrosive stream. In contrast, coke deposits generally have corrosive effects due to carburization, erosion and metal dusting. Because these approaches have not been entirely satisfactory, the accepted approach in the industry is to construct the distillation unit, or the portions exposed to naphthenic acid/sulfur corrosion, with the resistant metals such as high quality stainless steel or alloys containing higher amounts of chromium and molybdenum. The installation of corrosion - resistant alloys is capital intensive, as alloys such as 304 and 316 stainless steels are several times the cost of carbon steel. However, in units not so constructed there is a need to provide inhibition treatment against this type of corrosion. The prior art corrosion inhibitors for naphthenic acid environments include nitrogen-based filming corrosion inhibitors. 7 However, these corrosion inhibitors are relatively ineffective in the high temperature environment of naphthenic acid oils. While various corrosion inhibitors are known in various arts, the efficacy and usefulness of any particular corrosion inhibitor is dependent on the particular circumstances in which it is applied. Thus, efficacy or usefulness under one set of circumstances often does not imply the same for another set of circumstances. As a result, a large number of corrosion inhibitors have been developed and are in use for application to various systems depending on the medium treated, the type of surface that is susceptible to the corrosion, the type of corrosion encountered, and the conditions to which the medium is exposed. For example, U.S. Pat. No. 3,909,447 describes certain corrosion inhibitors as useful against corrosion in relatively low temperature oxygenated aqueous systems such as water floods, cooling towers, drilling muds, air drilling and auto radiator systems. That patent also notes that many corrosion inhibitors capable of performing in non-aqueous systems and/or non-oxygenated systems perform poorly in aqueous and/or oxygenated systems. The reverse is true as well. The mere fact that an inhibitor that has shown efficacy in oxygenated aqueous systems does not suggest that it would show efficacy in a hydrocarbon. Moreover, the mere fact that an inhibitor has been efficacious at relatively low temperatures does not indicate that it would be efficacious at elevated temperatures. In fact, it is common for inhibitors that are very effective at relatively low temperatures to become ineffective at temperatures such as the 175.degree. C. to 400.degree. C. encountered in oil refining. At such temperatures, corrosion is notoriously troublesome and difficult to alleviate. Thus, U.S. Pat. No. 3,909,447 contains no teaching or suggestion that it would be effective in non-aqueous systems such as hydrocarbon fluids, especially hot hydrocarbon fluids. Nor is there any indication in U.S. Pat. No. 3,909,447 that the compounds disclosed therein would be effective against naphthenic acid corrosion under such conditions. 8 Atmospheric and vacuum distillation systems are subject to naphthenic acid corrosion when processing certain crude oils. Currently used treatments are thermally reactive at use temperatures. In the case of phosphorus-based inhibitors, this is thought to lead to a metal phosphate surface film. The film is more resistant to naphthenic acid corrosion than the base steel. These inhibitors are relatively volatile and exhibit fairly narrow distillation ranges. They are fed into a column above or below the point of corrosion depending on the temperature range. Polysulfide inhibitors decompose into complex mixtures of higher and lower polysulfides and, perhaps, elemental sulfur and mercaptans. Thus, the volatility and protection offered is not predictable. The problems caused by naphthenic acid corrosion in refineries and the prior art solutions to that problem have been described at length in the literature, the following of which are representative: U.S. Pat. No. 3,531,394 to Koszman described the use of phosphorus and/or bismuth compounds in the cracking zone of petroleum steam furnaces to inhibit coke formation on the furnace tube walls. U.S. Pat. No. 3,531,394 to Koszman described the use of phosphorus and/or bismuth compounds in the cracking zone of petroleum steam furnaces to inhibit coke formation on the furnace tube walls. U.S. Pat. No. 4,024,049 to Shell et al discloses compounds substantially as described and claimed herein for use as refinery antifoulants. While effective as antifoulant materials, materials of this type have not heretofore been used as corrosion inhibitors in the manner set forth herein. While this reference teaches the addition of thiophosphate esters such as those used in the subject invention to the incoming feed, due to the non-volatile nature of the ester materials they do not distill into the column to protect the column, the pumparound piping, or further 9 process steps. I have found that by injecting the thiophosphate esters as taught herein, surprising activity is obtained in preventing the occurrence of naphthenic acid corrosion in distillation columns, pumparound piping, and associated equipment. U.S. Pat. No. 4,105,540 to Weinland describes phosphorus containing compounds as antifoulant additives in ethylene cracking furnaces. The phosphorus compounds employed are mono- and di-ester phosphate and phosphite compounds having at least one hydrogen moiety complexed with an amine. U.S. Pat. No. 4,443,609 discloses certain tetrahydrothiazole phosphonic acids and esters as being useful as acid corrosion inhibitors. Such inhibitors can be prepared by reacting certain 2,5-dihydrothiazoles with a dialkyl phosphite. While these tetrahydrothiazole phosphonic acids or esters have good corrosion and inhibition properties, they tend to break down during high temperature applications thereof with possible emission of obnoxious and toxic substances. It is also known that phosphorus-containing compounds impair the function of various catalysts used to treat crude oil, e.g., in fixed-bed hydrotreaters and hydrocracking units. Crude oil processors are often in a quandary since if the' phosphite stabilizer is not used, then iron can accumulate in the hydrocarbon up to 10 to 20 ppm and impair the catalyst. Although nonphosphorus-containing inhibitors are commercially available, they are generally less effective than the phosphorus-containing compounds. U.S. Pat. No. 4,542,253 to Kaplan et al, described an improved method of reducing fouling and corrosion in ethylene cracking furnaces using petroleum feedstocks including at least 10 ppm of a water soluble mine complexed phosphate, phosphite, thiophosphate or thiophosphite ester compound, wherein 10 the amine has a partition coefficient greater than 1.0 (equal solubility in both aqueous and hydrocarbon solvents). U.S. Pat. No. 4,842,716 to Kaplan et al describes an improved method for reducing fouling and corrosion at least 10 ppm of a combination of a phosphorus antifoulant compound and a filming inhibitor. The phosphorus compound is a phosphate, phosphite, thiophosphate or thiophosphite ester compound. The filming inhibitor is an imidazoline compound. U.S. Pat. No. 4,941,994 Zetmeisl et al discloses a naphthenic acid corrosion inhibitor comprising a dialkyl or trialkylphosphite in combination with an optional thiazoline. A significant advancement in phosphorus-containing naphthenic acid corrosion inhibitors was reported in U.S. Pat. No. 4,941,994, in which the present inventor is identified as a co-inventor. Therein it is disclosed that metal corrosion in hot acidic liquid hydrocarbons is inhibited by the presence of a corrosion inhibiting amount of a dialkyl and/or trialkyl phosphite with an optional thiazoline. While the method described in U.S. Pat. No. 4,941,994 provides significant improvements over the prior art techniques, nevertheless, there is always a desire to enhance the ability of corrosion inhibitors while reducing the amount of phosphorus-containing compounds which may impair the function of various catalysts used to treat crude oil, as well as a desire for such inhibitors that may be produced from lower cost or more available starting materials. Another approach to the prevention of naphthenic acid corrosion is the use of a chemical agent to form a barrier between the crude and the equipment of the hydrocarbon processing unit. This barrier or film prevents corrosive agents from reaching the metal surface, and is generally a hydrophobic material. Gustavsen et 11 al. NACE Corrosion 89 meeting, paper no. 449, Apr. 17-21, 1989 details the requirements for a good filming agent. U.S. Pat. No. 5,252,254 discloses one such film forming agent, sulfonated alkyl-substituted phenol, and effective against naphthenic acid corrosion. U.S. Pat. No. 5,182,013 issued to Petersen et al. on Jan. 26, 1993 describes another method of inhibiting naphthenic acid corrosion of crude oil, comprising introducing into the oil an effective amount of an organic polysulfide. The disclosure of U.S. Pat. No. 5,182,013 is incorporated herein by reference. This is another example of a corrosion-inhibiting sulfur species. Sulfidation as a source of corrosion was detailed above. Though the process is not well understood, it has been determined that while sulfur can be an effective anti-corrosive agent in small quantities, at sufficiently high concentrations, it becomes a corrosion agent. Phosphorus can form an effective barrier against corrosion without sulfur, but the addition of sulfiding agents to the process stream containing phosphorus yields a film composed of both sulfides and phosphates. This results in improved performance as well as a decreased phosphorus requirement. This invention pertains to the deliberate addition of sulfiding agents to the process stream when phosphorus-based materials are used for corrosion control to accentuate this interaction. US Patent No. 5,314,643 to Edmondson et at., describes a process for inhibition of corrosion caused by naphthenic acid and sulphur compounds during the elevated temperature processing of crude oil by use of a corrosion inhihitor consisting of a combination of trialkylphosphate and an alkaline earth metal phosphonate-phenate sulphide, functioning effectively as an inhibitor on the internal metallic surfaces of the equipment used in crude oil refining operations. 12 Organic polysulfides (Babaian-Kibala, U.S. Pat. No. 5,552,085), organic phosphites (Zetlmeisl, U.S. Pat. No. 4,941,994), and phosphate/phosphite esters (Babaian-Kibala, U.S. Pat. No. 5,630,964), have been claimed to be effective in hydrocarbon-rich phase against naphthenic acid corrosion. However, their high oil solubility incurs the risk of distillate side stream contamination by phosphorus. Phosphoric acid has been used primarily in aqueous phase for the formation of a phosphate/iron complex film on steel surfaces for corrosion inhibition or other applications (Coslett, British patent 8,667, U.S. Pat. Nos. 3,132,975, 3,460,989 and 1,872,091). Phosphoric acid use in high temperature non-aqueous environments (petroleum) has also been reported for purposes of fouling mitigation (U.S. Pat. No. 3,145,886). There remains a continuing need to develop additional options for mitigating the corrosivity of acidic crudes at lower cost. This is especially true at times of low refining margins and a high availability of corrosive crudes from sources such as Europe, China, or Africa, and India. The present invention addresses this need. DESCRIPTION OF THE INVENTION It has been surprisingly discovered by the inventor of the present invention, that a combination of organophosphorus sulphur compound and other phosphorus compound such as, phosphorous thioacid compound, that is, thiophosphite and / or thiophosphite esters, is very efficiently functioning in controlling naphthenic acid corrosion, providing a synergetic effect of combination of phosphorous compounds. The organophosphorus sulphur compound (A) is made from reaction of polyisobutylene with, phosphorus pentasulphide, in presence of sulphur powder. The other chemical compound (B), that is, phosphorous thioacid compound is made by reaction of alcohol and phosphorous pentasulphide. The 13 chemical compound (C ) is made by reacting the chemical compound (B) with cyclic oxides, such as ethylene oxide. The most effective amount of the corrosion inhihitor to be used in accordance with the present invention can vary depending on the local operating conditions and the particular hydrocarbon being processed. Thus, the temperature and other characteristics of the acid corrosion system can have a bearing on the amount of inhibitor or mixture of inhibitors to be used. Generally, where the operating temperatures and / or the acid concentrations are higher, a proportionately higher amount of the corrosion inhibitor will be required. It has been found that the concentration of the corrosion inhibitors or mixture of inhibitors added to the crude oil may range from about 1 ppm to 5000 ppm. It has also been found that it is preferred to add the inhibitors at a relatively high initial dosage rate of 2000-3000 ppm and to maintain this level for a relatively short period of time until the presence of the inhibitor induces the build-up of a corrosion protective coating on the metal surfaces. Once the protective surface is established, the dosage rate needed to maintain the protection may be reduced to a normal operational range of about 100-1500 ppm without substantial sacrifice of protection. The inventor of the present invention has carried out extensive experimentation to verify the effectiveness of corrosion - inhibition in case naphthenic acid corrosion, by experimenting with different proportions of compound (A), that is, polyisobutylene plus phosphorus pentasulphide plus sulphur powder and either of compound (B) and (C) . Experiments were also preformed by using compound (A) alone and compound (B) alone and compound (C) alone separately. The results of compound (A) alone and compound (C) alone are reported at present. 14 The reacted compound (A) is obtained by reaction of olefins with P2S5 (Phosphorus pentasulphide) in presence of sulphur powder. The preferred olefins have double bonds, whierein double bond is present internally or terminally. The example of internally double bonded olefins include beta-olefins. The example of terminally double bonded olefins include alpha-olefins. These olefins have 5 to 30 carbon atoms. These olefins are alternatively, polymeric olefins such as high reactive polyisobutylene containing greater than 70% of vinyledene double bond, and normal polysobutylenes which containsVinyl, vinyledene, and such other groups of chemicals. The ratio of P2S5 to Olefin is preferably 0.05 to 2 mole of P2S5 to 1 mole of Olefins. The Sulphur powder is present in catalytic quantity, that is, sulphur powder is 0.5% to 5% of Olefin by weight. The most preferred embodiment of the present invention is described below: A weighed quantity of HRPIB (High Reactive Polyisobutylene), phosphorous pentasulphide and sulphur powder are charged into a clean four - necked round bottom flask, equipped with nitrogen inlet, stirrer and thermometer, thereby forming a reaction mixture. This reaction mixture is stirred and heated to temperature of 160°C under nitrogen gas purging. At this temperature of 160 °C, the raction leads to evolution of hydrogen sulphide gas (H2S). The temperature of the reaction mixture is now maintained between 160°C to 180°C, for a period of 1 hour to 2 hours. Then the temperature of the mixture is raised to 220°C. The reaction mixture is then maintained at this temperature of 220 °C for 6 hours. 15 The resultant reaction mass is then cooled to temperature of 100 °C, when nitrogen gas is purged into the resultant reaction mass, to drive out the hydrogen sulphide present therein. The resulting polyisobutylene phosphorous sulphur compound is used as a high temperature naphthenic acid corrosion inhibitor. This compound is used neat or diluted in appropriate solvent such as xylene, toluene, and aromatic solvent as any other appropriate solvent to achieve inhibition of high temperature naphthenic acid corrosion. The present invention is directed to a method for inhibiting corrosion on the metal surfaces of the processing units which process hydrocarbons such as crude oil and its fractions containing naphthenic acid. The invention is explained in details in its simplest form wherein the following method steps are carried out, when it is used to process crude oil in process units such as distillation unit. Similar steps can be used in different processing units such as, pumparound piping, heat exchangers and such other processing units. These method steps are explained below: a) heating the hydrocarbon containing naphthenic acid to vaporize a portion of the hydrocarbon: b) allowing the hydrocarbon vapors to rise in a distillation column; c) condensing a portion of the hydrocarbon vapours passing through the distillation column to produce a distillate; d) adding to the distillate, from 5 to 2000 ppm of a combination (A) +(B) [(or a combination of (A) + (C)] compound of instant invention; e) allowing the distillate containing combination (A) + (B) compound [or a combination of (A) + (C)] to contact substantially the entire metal surfaces of the distillation unit to form protective film on such surface, whereby such surface is inhibited against corrosion. 16 It is advantageous to treat distillation column, trays, pumparound piping and related equipment to prevent naphthenic acid corrosion, when condensed vapours from distilled hydrocarbon fluids contact metallic equipment at temperatures greater than 200 °C, and preferably 400 °C. The combination (A) + (C) compound additive is generally added to the condensed distillate and the condensed distillate is allowed to contact the metallic surfaces of the distillation column, packing, trays, pump around piping and related equipment as the condensed distillate passes down the column and into the distillation vessel. The distillate may also be collected as product. The corrosion inhibitors of the instant invention remain in the resultant collected product. In commercial practice, the additives of this invention may be added to a distillate return to control corrosion in a draw tray and in the column packing while a second injection may be added to a spray oil return immediately below the draw trays to protect the tower packing and trays below the distillate draw tray. It is not so critical where the additive of the invention is added as long as it is added to distillate that is later returned to the distillation vessel, or which contact the metal interior surfaces of the distillation column, trays, pump around piping and related equipments. The method of using the polyisobutylene phosphorous sulphur compound of the present invention for achieving inhibition of high temperature naphthenic acid corrosion is explained below with the help of examples 1 and 2. EXAMPLE 1 A weighed quantity of HRPIB (High Reactive Polyisobutylene), Phosphorus pentasulphide and sulphur powder are charged into a clean four - necked round bottom flask, equipped with nitrogen inlet, stirrer and thermometer, thereby forming a reaction mixture. 17 The weighed quantities mentioned above are : HRPIB = 68.16 gm P2S5 = 30.31 gm Sulphur Powder = 1.51gm Total =100gm This gives 1:1 mole ratio of P2S5 to Olefin. This reaction mixture was stirred and heated to temperature of 160°C under nitrogen gas purging. At this temperature of 160 °C, the reaction led to evolution of hydrogen sulphide gas (H2S). The temperature of the reaction mixture was now maintained between 160°C to 180°C, for a period of 1 hour to 2 hours. Then the temperature of the mixture was raised to 220°C. The reaction mixture was then maintained at this temperature of 220 °C for 6 hours. The resultant reaction mass was then cooled to temperature of 100 °C, when nitrogen gas was purged into the resultant reaction mass, to drive out the hydrogen sulphide present therein. The resulting polyisobutylene phosphorous sulphur compound was used as a high temperature naphthenic acid corrosion inhibitor. This compound was used neat or diluted in appropriate solvent such as xylene, toluene, and aromatic solvent as any other appropriate solvent to achieve inhibition of high temperature naphthenic acid corrosion. EXAMPLE 2 High temperature naphthenic acid corrosion test: In this example, various amounts of a 50% formulation of the composition prepared in accordance, with Example 1, above, were tested for corrosion 18 inhibitive efficacy on steel coupons in a hot oil containing naphthenic acid. This test is described below in details. A weight loss coupon, immersion test was used to evaluate the invention compound for its effectiveness in inhibition of naphthenic acid corrosion at 290 °C temperature. Chemicals / Materials used : Compounds of Example 1 is different dosages such as 200, 300 and 400 ppm were used in these experiments. Specification of Chemicals / Materials used Hydrocarbon oil of Grade D - 130 was distilled to remove the lower boiling fraction and the fraction having boiling point between 290 °C and 324 °C was used for testing efficiency in inhibition of naphthenic corrosion. The detailed specifications are given below: (i) Hydrocarbon oil (D -130) (residue after discard distillate at 290C): PMCC = Pensky Martin Close Cup IBP = Initial Boiling Point FBP = Final Boiling Point Appearance = Clear light, yellow colour liquid Specific gravity at 32 °C = 0.8160 Viscosity at 38 °C =8.14 Flash point (PMCC) =138°C Pour point = - 6 °C 19 IBP = 290 °C FBP = 324 °C Acid value = NIL Sulphur content = (ii) Weight loss coupon: CS = Carbon Steel a) Material =CS 1010 b) Dimension = 76mm x 13mm x 1.6mm Diameter of hole = 5.5mm c) Chemical analysis of coupon Elements weight % C 0.09 Mn 0.33 P 0.008 S 0.007 Si 0.02 Al 0.051 Cu 0.01 Mo 0.01 Sn 0.002 Sb 0.002 N 0.0031 Cr 0.02 Ni 0.01 Ti 0.002 20 (iii) Naphthenic acid; Grade Commercial Acid value 230 mg KOH / gm Apparatus used (i) Four - necked round bottom flask (one liter capacity) (ii) Water condenser (iii) Thermometer pocket with thermometer (iv) Heating mental with temperature regulator (v) N2 gas purging tube (with bottom bulb) (vi) Rotameter for N2 gas purging (vii) Glass stirrer rod ("S" shaped bottom) (viii) Pipettes (ix) Glass beaker (x) Measuring cylinder (xi) Glass rod (bottom bend) for holding coupons (xii) Teflon tape (xiii) Teflon cork Test conditions (i) Temperature = 290 °C (ii) N2 gas flow rate = 110cc/min (iii) TAN of system after adding Naphthenic acid = about 12 (iv) Product doping temperature = 100°C (v) Time for stirring after doping = 15 minutes (vi) Coupon passivation time = 1 hour at 290 °C 21 (vii) Immersion time of coupon in the corrosive medium = 4 hours at 290 °C Test Procedure: 1) 600 gm ( about 750 ml) paraffinic hydrocarbon oil (D -130) was taken in a one -liter four necked round bottom flask equipped with water condenser, N2 purger tube, thermometer pocket with thermometer and stirrer rod; 2) N2 gas purging was started with flow rate of 110 cc / min and temperature was raised to 100 °C. This temperature of 100 °C was maintained for 30 minutes deairation; 3) The inhibitor compound of the present invention that is, compound comprising Polyisobutylene and Phosphorous pentasulphide with sulphur powder was added to the reaction mixture; 4) Stirring of the reaction mixture was started and the stirring was continued for a period of 15 minutes at the temperature of 100 °C; 5) The stirrer was removed and the temperature of the reaction mixture was raised to 290 °C; 6) The pre - weighed metal coupon of weight "W1” gm, was immersed in the reaction mixture with the help of the glass rod and Teflon tape; 7) Simultaneously N2 gas flow was continued , at flow rate of 110 cc / min; 8) This condition of reaction mixture that is, N2 gas flow rate mentioned above and temperature of 290 °C was maintained for passivation time of 1 hour; 9) After one hour, naphthenic acid of weight 31 gm was added to the reaction mixture and the condition (of item 8 above) of reaction mixture was now maintained for next 4 hours; 22 10) A sample of one gm weight was collected from the reaction flask for determination of acid value; (acid value of the reaction mixture after addition of naphthenic acid = approximately 11.7); 11) After completion of the above mentioned period of 4 hours of step (9), the metal coupon was removed and cleaned by scrubbing the metal coupon with soft paper and hexane and then was dried and reweighed as having weight "W2" mg; 12) The weight loss of the metal coupon is measured as "W", wherein W = (W, - W2) mg; 13) The general corrosion rate in MPY (mills per year) is calculated by the formula MPY = 534 x Weight loss in gm (Density in gm/cc) x (Area in in2) x (Time of test in hours) Table 1 Exper iment Sr.No. Inhibitor Dosageinppm Weightlossinmg Corrosion Rate MPY Corrosion Inhibitors Efficiency in% 1 Only metalblank(No inhibitorCompound) 89.5 524.89 2 50% active Compound of Example 1, (Polyisobutylene, Phosphorus penta sulphide and sulphur powder) and 50% solvent 200 63.3 371.23 29.27 3 Compound as per experimentNo. 2 300 39.6 232.24 55.76 4 Compound as per experimentNo. 2 400 15.2 89.114 83.02 23 EXAMPLE 3 The clean four - necked - flask was equipped with stirrer, nitrogen gas inlet and condenser. The noctanol weighing 400gms was charged in the flask. The phosphorous pentasulphide weighing 187 gms, was then added to the flask in installments. The temperature of the flask was then increased to 110 degree C. The gas H2S was seen to be evolved after addition of P2S5. After one hour, the reaction mixture in the flask was heated to 140 degree C and the flask was maintained at that temperature for one hour. The acid value of the reaction mixture was about 125 mg/KOH. This reaction mixture was then transferred to the autoclave, and ethylene oxide was added till the pressure remained constant, thereby indicating no further absorption of the ethylene oxide by the reaction mixture. The system was then purged with nitrogen gas to remove the excess of ethylene oxide. The acid value of the final product was about 25 mg/KOH. EXAMPLE 4 Experiments were carried out by the inventor of the present invention, to test the synergetic effectiveness of a combination of the compounds (A) and (C), where compound (A) represents polyisobutylene plus phosphorous pentasulphide plus sulphur powder and compound (C) represents the resulting reaction compound when the chemical compound (B) is reacted with cyclic oxides such as ethylene oxide. Different total dosages of inhibitor compounds' combination such as 300 ppm and 360 ppm were used in the experimentation. Similarly, different proportions of compound (A) and compound (C), were used in these experiments. The percentage proportions of (A): (C) was 50:50. The result of these experiments are presented in Table 2.. 24 The results of the experiments are presented in Table 2 ExperimentNo. Compound (A) dosageIn ppm (50% wasactive) Compound (C) dosagein ppm (50 % wasactive) Ratio (A): (C) TotalDosage inppm Weight loss in mg. 1 200 200 63.3 2 300 300 39.6 3 400 — 400 15.2 4 150 150 39.6 5 180 180 21.1 6 150 150 1:1 300 8.1 7 180 180 1:1 360 0.2 25

Full Text

FORM 2
THE PATENTS ACT 1970
(39 of 1970)
&
The Patent Rules, 2003
Provisional Specification
(See section 10 and rule 13)
A novel additive for naphthenic acid corrosion inhibition and method of
using the same.
Dorf Ketal Chemicals (I) Pvt. Ltd
Dorf Ketal Tower, D'monte Street, Orlem, Malad (W), Mumbai, 400064 Maharashtra
State, India.
An Indian company registered under the Companies Act, 1956
The following specification describes the invention:

A NOVEL ADDITIVE FOR NAPHTHENIC ACID CORROSION INHIBITION AND METHOD OF USING THE SAME.
FIELD OF THE INVENTION
The present invention relates to the inhibition of metal corrosion in acidic hot hydrocarbons and more particularly to he inhibition of corrosion of iron -containing metals in hot acidic hydrocarbons, especially when the acidity is derived from the presence of naphthenic acid.
DISCUSSION OF PRIOR ART
It is widely known in the art that the processing of crude oil and its various fractions has led to damage to piping and other associated equipment due to naphthenic acid corrosion. These are corrosive to the equipment used to distill, extract, transport and process the crudes. Generally speaking, naphthenic acid corrosion occurs when the crude being processed has a neutralization number or total acid number (TAN), expressed as the milligrams of potassium hydroxide required to neutralize the acids in a one gram sample, above 0.2. It is also known that naphthenic acid-containing hydrocarbon is at a temperature between about 200.degree. C. and 400.degree. C. (approximately 400.degree. F.-750.degree. F.), and also when fluid velocities are high or liquid impinges on process surfaces e.g. in transfer lines, return bends and restricted flow areas.
Corrosion problems in petroleum refining operations associated with naphthenic acid constituents and sulfur compounds in crude oils have been recognized for many years. Such corrosion is particularly severe in atmospheric and vacuum distillation units at temperatures between 400.degree. F. and 790.degree. F. Other factors that contribute to the corrosivity of crudes containing naphthenic acids include the amount of naphthenic acid present, the concentration of sulfur
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compounds, the velocity and turbulence of the flow stream in the units, and the location in the unit (e.g., liquid/vapor interface).
As commonly used, naphthenic acid is a collective term for certain organic acids present in various crude oils. Although there may be present minor amounts of other organic acids, it is understood that the majority of the acids in naphthenic based crude are naphthenic in character, i.e., with a saturated ring structure as follows:

The molecular weight of naphthenic acid can extend over a large range. However, the majority of the naphthenic acid from crude oils is found in gas oil and light lubricating oil. 15 When hydrocarbons containing such naphthenic acid contact iron-containing metals, especially at elevated temperatures, severe corrosion problems arise.
Naphthenic acid corrosion has plagued the refining industry for many years. This corroding material consists of predominantly monocyclic or bicyclic carboxylic acids with a boiling range between 350.degree. and 650.degree. F. These acids tend to concentrate in the heavier fractions during crude distillation. Thus, locations such as the furnace tubing, transfer lines, fractionating tower internals, feed and reflux sections of columns, heat exchangers, tray bottoms and condensers are primary sites of attack for naphthenic acid. Additionally, when crude stocks high in naphthenic acids are processed, severe corrosion can occur in the carbon steel or ferritic steel furnace tubes and tower bottoms. Recently interest has grown in the control of this type of corrosion in hydrocarbon processing units due to the presence of naphthenic acid in crudes from locations such as China, India, Africa and Europe.
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Crude oils are hydrocarbon mixtures which have a range of molecular structures and consequent range of physical properties. The physical properties of naphthenic acids which may be contained in the hydrocarbon mixtures also vary with the changes in molecular weight, as well as the source of oil containing the acid. Therefore, characterization and behavior of these acids are not well understood. A well known method used to "quantify" the acid concentration in crude oil has been a KOH titration of the oil. The oil is titrated with KOH, a strong base, to an end point which assures that all acids in the sample have been neutralized. The unit of this titration is mg. of KOH/gram of sample and is referred to as the "Total Acid Number" (TAN) or Neutralization Number. Both terms are used interchangeably in the application.
The unit of TAN is commonly used since it is not possible to calculate the acidity of the oil in terms of moles of acid, or any other of the usual analytical terms for acid content. Refiners have used TAN as a general guideline for predicting naphthenic acid corrosion. For example, many refineries blend their crude to a TAN=0.5 assuming that at these concentrations naphthenic acid corrosion will not occur. However, this measure has been unsuccessful in preventing corrosion by naphthenic acid.
Naphthenic acid corrosion is very temperature dependent. The generally accepted temperature range for this corrosion is between 205.degree. C. and 400.degree. C. (400.degree. F. and 750.degree. F.). Corrosion attack by these acids below 205.degree. C. has not yet been reported in the published literature. As to the upper boundary, data suggests that corrosion rates reach a maximum at about 600.degree.-700.degree. F. and then begin to diminish.
The concentration and velocity of the acid/oil mixture are also important factors which influence naphthenic acid corrosion. This is evidenced by the appearance of
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the surfaces affected by naphthenic acid corrosion. The manner of corrosion can be deduced from the patterns and color variations in the corroded surfaces. Under some conditions, the metal surface is uniformly thinned. Thinned areas also occur when condensed acid runs down the wall of a vessel. Alternatively, in the presence of naphthenic acid pitting occurs, often in piping or at welds. Usually the metal outside the pit is covered with a heavy, black sulfide film, while the surface of the pit is bright metal or has only a thin, grey to black film covering it. Moreover, another pattern of corrosion is erosion-corrosion, which has a characteristic pattern of gouges with sharp edges. The surface appears clean, with no visible by-products. The pattern of metal corrosion is indicative of the fluid flow within the system, since increased contact with surfaces allows for a greater amount of corrosion to- take place. Therefore, corrosion patterns provide information as to the method of corrosion which has taken place. Also, the more complex the corrosion, i.e., in increasing complexity from uniform to pitting to erosion-corrosion, the lower is the TAN value which triggers the behavior.
The information provided by corrosion patterns indicates whether naphthenic acid is the corroding agent, or rather if the process of corrosion occurs as a result of attack by sulfur. Most crude contain hydrogen sulfide, and therefore readily form iron sulfide films on carbon steel. In all cases that have been observed in the laboratory or in the field, metal surfaces have been covered with a film of some sort. In the presence of hydrogen sulfide the film formed is invariably iron sulfide, while in the few cases where tests have been run in sulfur free conditions, the metal is covered with iron oxide, as there is always enough water or oxygen present to produce a thin film on the metal coupons.
Tests utilized to determine the extent of corrosion may also serve as indicators of the type of corrosion occurring within a particular hydrocarbon treating unit. Metal coupons can be inserted into the system. As they are corroded, they lose material. This weight loss is recorded in units of mg/cm.sup.2. Thereafter, the
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corrosion rate can be determined from weight loss measurements. Then the ratio of corrosion rate to corrosion product (mpy/mg/cm.sup.2) is calculated. This is a further indicator of the type of corrosion process which has taken place, for if this ratio is less than 10, it has been found that there is little or no contribution of naphthenic acid to the corrosion process. However, if the ratio exceeds 10, then naphthenic acid is a significant contributor to the corrosion process.
Distinguishing between sulfidation attack and corrosion caused by naphthenic acid is important, since different remedies are required depending upon the corroding agent. Usually, retardation of corrosion caused by sulfur compounds at elevated temperatures is effected by increasing the amount of chromium in the alloy which is used in the hydrocarbon treating unit. A range of alloys may be employed, from 1.25% Cr to 12% Cr, or perhaps even higher. Unfortunately, these show little to no resistance to naphthenic acid. To compensate for the corroding effects of sulfur and naphthenic acid, an austenitic stainless steel which contains at least 2.5% molybdenum, must be utilized. The corrosive problem is known to be aggravated by the elevated temperatures necessary to refine and crack the oil and by the oil's acidity which is caused primarily by high levels of naphthenic acid indigenous to the crudes.Naphthenic acids is corrosive between the range of about 175 degree C to 420.degree. C. At the higher temperatures the naphthenic acids are in the vapor phase and at the lower temperatures the corrosion rate is not serious. The corrosivity of naphthenic acids appears to be exceptionally serious in the presence of sulfide compounds, such as hydrogen sulfide, mercaptans, elemental sulfur, sulfides, disulfides, polysulfides and thiophenols. Corrosion due to sulfur compounds becomes significant at temperatures as low as 450.degree. F. The catalytic generation of hydrogen sulfide by thermal decomposition of mercaptans has been identified as a cause of sulfidic corrosion.
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Sulfur in the crudes, which produces hydrogen sulfide at higher temperatures, also aggravates the problem. The temperature range of primary interest for this type of corrosion is in the range of about 175.degree. C. to about 400.degree. C, especially about 205.degree. C. to about 400.degree. C.
Various approaches to controlling naphthenic acid corrosion have included neutralization and/or removal of naphthenic acids from the crude being processed; blending low acid number oils with corrosive high acid number oils to reduce the overall neutralization number; and the use of relatively expensive corrosion-resistant alloys in the construction of the piping and associated equipment. These attempts are generally disadvantageous in that they require additional processing and/or add substantial costs to treatment of the crude oil. Alternatively, various amine and amide based corrosion inhibitors are commercially available, but these are generally ineffective in the high temperature environment of naphthenic acid corrosion. Naphthenic acid corrosion is readily distinguished from conventional fouling problems such as coking and polymer deposition which can occur in ethylene cracking and other hydrocarbon processing reactions using petroleum based feedstocks. Naphthenic acid corrosion produces a characteristic grooving of the metal in contact with the corrosive stream. In contrast, coke deposits generally have corrosive effects due to carburization, erosion and metal dusting.
Because these approaches have not been entirely satisfactory, the accepted approach in the industry is to construct the distillation unit, or the portions exposed to naphthenic acid/sulfur corrosion, with the resistant metals such as high quality stainless steel or alloys containing higher amounts of chromium and molybdenum. The installation of corrosion - resistant alloys is capital intensive, as alloys such as 304 and 316 stainless steels are several times the cost of carbon steel. However, in units not so constructed there is a need to provide inhibition treatment against this type of corrosion. The prior art corrosion inhibitors for naphthenic acid environments include nitrogen-based filming corrosion inhibitors.
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However, these corrosion inhibitors are relatively ineffective in the high temperature environment of naphthenic acid oils.
While various corrosion inhibitors are known in various arts, the efficacy and usefulness of any particular corrosion inhibitor is dependent on the particular circumstances in which it is applied. Thus, efficacy or usefulness under one set of circumstances often does not imply the same for another set of circumstances. As a result, a large number of corrosion inhibitors have been developed and are in use for application to various systems depending on the medium treated, the type of surface that is susceptible to the corrosion, the type of corrosion encountered, and the conditions to which the medium is exposed. For example, U.S. Pat. No. 3,909,447 describes certain corrosion inhibitors as useful against corrosion in relatively low temperature oxygenated aqueous systems such as water floods, cooling towers, drilling muds, air drilling and auto radiator systems. That patent also notes that many corrosion inhibitors capable of performing in non-aqueous systems and/or non-oxygenated systems perform poorly in aqueous and/or oxygenated systems. The reverse is true as well. The mere fact that an inhibitor that has shown efficacy in oxygenated aqueous systems does not suggest that it would show efficacy in a hydrocarbon. Moreover, the mere fact that an inhibitor has been efficacious at relatively low temperatures does not indicate that it would be efficacious at elevated temperatures. In fact, it is common for inhibitors that are very effective at relatively low temperatures to become ineffective at temperatures such as the 175.degree. C. to 400.degree. C. encountered in oil refining. At such temperatures, corrosion is notoriously troublesome and difficult to alleviate. Thus, U.S. Pat. No. 3,909,447 contains no teaching or suggestion that it would be effective in non-aqueous systems such as hydrocarbon fluids, especially hot hydrocarbon fluids. Nor is there any indication in U.S. Pat. No. 3,909,447 that the compounds disclosed therein would be effective against naphthenic acid corrosion under such conditions.
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Atmospheric and vacuum distillation systems are subject to naphthenic acid corrosion when processing certain crude oils. Currently used treatments are thermally reactive at use temperatures. In the case of phosphorus-based inhibitors, this is thought to lead to a metal phosphate surface film. The film is more resistant to naphthenic acid corrosion than the base steel. These inhibitors are relatively volatile and exhibit fairly narrow distillation ranges. They are fed into a column above or below the point of corrosion depending on the temperature range. Polysulfide inhibitors decompose into complex mixtures of higher and lower polysulfides and, perhaps, elemental sulfur and mercaptans. Thus, the volatility and protection offered is not predictable.
The problems caused by naphthenic acid corrosion in refineries and the prior art solutions to that problem have been described at length in the literature, the following of which are representative:
U.S. Pat. No. 3,531,394 to Koszman described the use of phosphorus and/or bismuth compounds in the cracking zone of petroleum steam furnaces to inhibit coke formation on the furnace tube walls.
U.S. Pat. No. 3,531,394 to Koszman described the use of phosphorus and/or bismuth compounds in the cracking zone of petroleum steam furnaces to inhibit coke formation on the furnace tube walls.
U.S. Pat. No. 4,024,049 to Shell et al discloses compounds substantially as described and claimed herein for use as refinery antifoulants. While effective as antifoulant materials, materials of this type have not heretofore been used as corrosion inhibitors in the manner set forth herein. While this reference teaches the addition of thiophosphate esters such as those used in the subject invention to the incoming feed, due to the non-volatile nature of the ester materials they do not distill into the column to protect the column, the pumparound piping, or further
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process steps. I have found that by injecting the thiophosphate esters as taught herein, surprising activity is obtained in preventing the occurrence of naphthenic acid corrosion in distillation columns, pumparound piping, and associated equipment.
U.S. Pat. No. 4,105,540 to Weinland describes phosphorus containing compounds as antifoulant additives in ethylene cracking furnaces. The phosphorus compounds employed are mono- and di-ester phosphate and phosphite compounds having at least one hydrogen moiety complexed with an amine.
U.S. Pat. No. 4,443,609 discloses certain tetrahydrothiazole phosphonic acids and esters as being useful as acid corrosion inhibitors. Such inhibitors can be prepared by reacting certain 2,5-dihydrothiazoles with a dialkyl phosphite. While these tetrahydrothiazole phosphonic acids or esters have good corrosion and inhibition properties, they tend to break down during high temperature applications thereof with possible emission of obnoxious and toxic substances.
It is also known that phosphorus-containing compounds impair the function of various catalysts used to treat crude oil, e.g., in fixed-bed hydrotreaters and hydrocracking units. Crude oil processors are often in a quandary since if the' phosphite stabilizer is not used, then iron can accumulate in the hydrocarbon up to 10 to 20 ppm and impair the catalyst. Although nonphosphorus-containing inhibitors are commercially available, they are generally less effective than the phosphorus-containing compounds.
U.S. Pat. No. 4,542,253 to Kaplan et al, described an improved method of reducing fouling and corrosion in ethylene cracking furnaces using petroleum feedstocks including at least 10 ppm of a water soluble mine complexed phosphate, phosphite, thiophosphate or thiophosphite ester compound, wherein
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the amine has a partition coefficient greater than 1.0 (equal solubility in both aqueous and hydrocarbon solvents).
U.S. Pat. No. 4,842,716 to Kaplan et al describes an improved method for reducing fouling and corrosion at least 10 ppm of a combination of a phosphorus antifoulant compound and a filming inhibitor. The phosphorus compound is a phosphate, phosphite, thiophosphate or thiophosphite ester compound. The filming inhibitor is an imidazoline compound.
U.S. Pat. No. 4,941,994 Zetmeisl et al discloses a naphthenic acid corrosion inhibitor comprising a dialkyl or trialkylphosphite in combination with an optional thiazoline.
A significant advancement in phosphorus-containing naphthenic acid corrosion inhibitors was reported in U.S. Pat. No. 4,941,994, in which the present inventor is identified as a co-inventor. Therein it is disclosed that metal corrosion in hot acidic liquid hydrocarbons is inhibited by the presence of a corrosion inhibiting amount of a dialkyl and/or trialkyl phosphite with an optional thiazoline.
While the method described in U.S. Pat. No. 4,941,994 provides significant improvements over the prior art techniques, nevertheless, there is always a desire to enhance the ability of corrosion inhibitors while reducing the amount of phosphorus-containing compounds which may impair the function of various catalysts used to treat crude oil, as well as a desire for such inhibitors that may be produced from lower cost or more available starting materials.
Another approach to the prevention of naphthenic acid corrosion is the use of a chemical agent to form a barrier between the crude and the equipment of the hydrocarbon processing unit. This barrier or film prevents corrosive agents from reaching the metal surface, and is generally a hydrophobic material. Gustavsen et
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al. NACE Corrosion 89 meeting, paper no. 449, Apr. 17-21, 1989 details the requirements for a good filming agent. U.S. Pat. No. 5,252,254 discloses one such film forming agent, sulfonated alkyl-substituted phenol, and effective against naphthenic acid corrosion.
U.S. Pat. No. 5,182,013 issued to Petersen et al. on Jan. 26, 1993 describes another method of inhibiting naphthenic acid corrosion of crude oil, comprising introducing into the oil an effective amount of an organic polysulfide. The disclosure of U.S. Pat. No. 5,182,013 is incorporated herein by reference. This is another example of a corrosion-inhibiting sulfur species. Sulfidation as a source of corrosion was detailed above. Though the process is not well understood, it has been determined that while sulfur can be an effective anti-corrosive agent in small quantities, at sufficiently high concentrations, it becomes a corrosion agent.
Phosphorus can form an effective barrier against corrosion without sulfur, but the addition of sulfiding agents to the process stream containing phosphorus yields a film composed of both sulfides and phosphates. This results in improved performance as well as a decreased phosphorus requirement. This invention pertains to the deliberate addition of sulfiding agents to the process stream when phosphorus-based materials are used for corrosion control to accentuate this interaction.
US Patent No. 5,314,643 to Edmondson et at., describes a process for inhibition of corrosion caused by naphthenic acid and sulphur compounds during the elevated temperature processing of crude oil by use of a corrosion inhihitor consisting of a combination of trialkylphosphate and an alkaline earth metal phosphonate-phenate sulphide, functioning effectively as an inhibitor on the internal metallic surfaces of the equipment used in crude oil refining operations.
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Organic polysulfides (Babaian-Kibala, U.S. Pat. No. 5,552,085), organic phosphites (Zetlmeisl, U.S. Pat. No. 4,941,994), and phosphate/phosphite esters (Babaian-Kibala, U.S. Pat. No. 5,630,964), have been claimed to be effective in hydrocarbon-rich phase against naphthenic acid corrosion. However, their high oil solubility incurs the risk of distillate side stream contamination by phosphorus.
Phosphoric acid has been used primarily in aqueous phase for the formation of a phosphate/iron complex film on steel surfaces for corrosion inhibition or other applications (Coslett, British patent 8,667, U.S. Pat. Nos. 3,132,975, 3,460,989 and 1,872,091). Phosphoric acid use in high temperature non-aqueous environments (petroleum) has also been reported for purposes of fouling mitigation (U.S. Pat. No. 3,145,886).
There remains a continuing need to develop additional options for mitigating the corrosivity of acidic crudes at lower cost. This is especially true at times of low refining margins and a high availability of corrosive crudes from sources such as Europe, China, or Africa, and India. The present invention addresses this need.
DESCRIPTION OF THE INVENTION
It has been surprisingly discovered by the inventor of the present invention, that a combination of organophosphorus sulphur compound and other phosphorus compound such as, phosphorous thioacid compound, that is, thiophosphite and / or thiophosphite esters, is very efficiently functioning in controlling naphthenic acid corrosion, providing a synergetic effect of combination of phosphorous compounds. The organophosphorus sulphur compound (A) is made from reaction of polyisobutylene with, phosphorus pentasulphide, in presence of sulphur powder. The other chemical compound (B), that is, phosphorous thioacid compound is made by reaction of alcohol and phosphorous pentasulphide. The
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chemical compound (C ) is made by reacting the chemical compound (B) with cyclic oxides, such as ethylene oxide.
The most effective amount of the corrosion inhihitor to be used in accordance with the present invention can vary depending on the local operating conditions and the particular hydrocarbon being processed. Thus, the temperature and other characteristics of the acid corrosion system can have a bearing on the amount of inhibitor or mixture of inhibitors to be used. Generally, where the operating temperatures and / or the acid concentrations are higher, a proportionately higher amount of the corrosion inhibitor will be required. It has been found that the concentration of the corrosion inhibitors or mixture of inhibitors added to the crude oil may range from about 1 ppm to 5000 ppm. It has also been found that it is preferred to add the inhibitors at a relatively high initial dosage rate of 2000-3000 ppm and to maintain this level for a relatively short period of time until the presence of the inhibitor induces the build-up of a corrosion protective coating on the metal surfaces.
Once the protective surface is established, the dosage rate needed to maintain the protection may be reduced to a normal operational range of about 100-1500 ppm without substantial sacrifice of protection.
The inventor of the present invention has carried out extensive experimentation to verify the effectiveness of corrosion - inhibition in case naphthenic acid corrosion, by experimenting with different proportions of compound (A), that is, polyisobutylene plus phosphorus pentasulphide plus sulphur powder and either of compound (B) and (C) . Experiments were also preformed by using compound (A) alone and compound (B) alone and compound (C) alone separately. The results of compound (A) alone and compound (C) alone are reported at present.
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The reacted compound (A) is obtained by reaction of olefins with P2S5 (Phosphorus pentasulphide) in presence of sulphur powder. The preferred olefins have double bonds, whierein double bond is present internally or terminally.
The example of internally double bonded olefins include beta-olefins.
The example of terminally double bonded olefins include alpha-olefins. These olefins have 5 to 30 carbon atoms. These olefins are alternatively, polymeric olefins such as high reactive polyisobutylene containing greater than 70% of vinyledene double bond, and normal polysobutylenes which containsVinyl, vinyledene, and such other groups of chemicals.
The ratio of P2S5 to Olefin is preferably 0.05 to 2 mole of P2S5 to 1 mole of Olefins. The Sulphur powder is present in catalytic quantity, that is, sulphur powder is 0.5% to 5% of Olefin by weight.
The most preferred embodiment of the present invention is described below: A weighed quantity of HRPIB (High Reactive Polyisobutylene), phosphorous pentasulphide and sulphur powder are charged into a clean four - necked round bottom flask, equipped with nitrogen inlet, stirrer and thermometer, thereby forming a reaction mixture.
This reaction mixture is stirred and heated to temperature of 160°C under nitrogen gas purging. At this temperature of 160 °C, the raction leads to evolution of hydrogen sulphide gas (H2S). The temperature of the reaction mixture is now maintained between 160°C to 180°C, for a period of 1 hour to 2 hours. Then the temperature of the mixture is raised to 220°C. The reaction mixture is then maintained at this temperature of 220 °C for 6 hours.
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The resultant reaction mass is then cooled to temperature of 100 °C, when nitrogen gas is purged into the resultant reaction mass, to drive out the hydrogen sulphide present therein. The resulting polyisobutylene phosphorous sulphur compound is used as a high temperature naphthenic acid corrosion inhibitor. This compound is used neat or diluted in appropriate solvent such as xylene, toluene, and aromatic solvent as any other appropriate solvent to achieve inhibition of high temperature naphthenic acid corrosion.
The present invention is directed to a method for inhibiting corrosion on the metal surfaces of the processing units which process hydrocarbons such as crude oil and its fractions containing naphthenic acid. The invention is explained in details in its simplest form wherein the following method steps are carried out, when it is used to process crude oil in process units such as distillation unit. Similar steps can be used in different processing units such as, pumparound piping, heat exchangers and such other processing units.
These method steps are explained below:
a) heating the hydrocarbon containing naphthenic acid to vaporize a portion of the hydrocarbon:
b) allowing the hydrocarbon vapors to rise in a distillation column;
c) condensing a portion of the hydrocarbon vapours passing through the distillation column to produce a distillate;
d) adding to the distillate, from 5 to 2000 ppm of a combination (A) +(B) [(or a combination of (A) + (C)] compound of instant invention;
e) allowing the distillate containing combination (A) + (B) compound [or a combination of (A) + (C)] to contact substantially the entire metal surfaces of the distillation unit to form protective film on such surface, whereby such surface is inhibited against corrosion.
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It is advantageous to treat distillation column, trays, pumparound piping and related equipment to prevent naphthenic acid corrosion, when condensed vapours from distilled hydrocarbon fluids contact metallic equipment at temperatures greater than 200 °C, and preferably 400 °C. The combination (A) + (C) compound additive is generally added to the condensed distillate and the condensed distillate is allowed to contact the metallic surfaces of the distillation column, packing, trays, pump around piping and related equipment as the condensed distillate passes down the column and into the distillation vessel. The distillate may also be collected as product. The corrosion inhibitors of the instant invention remain in the resultant collected product.
In commercial practice, the additives of this invention may be added to a distillate return to control corrosion in a draw tray and in the column packing while a second injection may be added to a spray oil return immediately below the draw trays to protect the tower packing and trays below the distillate draw tray. It is not so critical where the additive of the invention is added as long as it is added to distillate that is later returned to the distillation vessel, or which contact the metal interior surfaces of the distillation column, trays, pump around piping and related equipments.
The method of using the polyisobutylene phosphorous sulphur compound of the present invention for achieving inhibition of high temperature naphthenic acid corrosion is explained below with the help of examples 1 and 2.
EXAMPLE 1
A weighed quantity of HRPIB (High Reactive Polyisobutylene), Phosphorus pentasulphide and sulphur powder are charged into a clean four - necked round bottom flask, equipped with nitrogen inlet, stirrer and thermometer, thereby forming a reaction mixture.
17

The weighed quantities mentioned above are :
HRPIB = 68.16 gm
P2S5 = 30.31 gm
Sulphur Powder = 1.51gm
Total =100gm
This gives 1:1 mole ratio of P2S5 to Olefin.
This reaction mixture was stirred and heated to temperature of 160°C under nitrogen gas purging. At this temperature of 160 °C, the reaction led to evolution of hydrogen sulphide gas (H2S). The temperature of the reaction mixture was now maintained between 160°C to 180°C, for a period of 1 hour to 2 hours. Then the temperature of the mixture was raised to 220°C. The reaction mixture was then maintained at this temperature of 220 °C for 6 hours.
The resultant reaction mass was then cooled to temperature of 100 °C, when nitrogen gas was purged into the resultant reaction mass, to drive out the hydrogen sulphide present therein. The resulting polyisobutylene phosphorous sulphur compound was used as a high temperature naphthenic acid corrosion inhibitor. This compound was used neat or diluted in appropriate solvent such as xylene, toluene, and aromatic solvent as any other appropriate solvent to achieve inhibition of high temperature naphthenic acid corrosion.
EXAMPLE 2
High temperature naphthenic acid corrosion test:
In this example, various amounts of a 50% formulation of the composition prepared in accordance, with Example 1, above, were tested for corrosion
18

inhibitive efficacy on steel coupons in a hot oil containing naphthenic acid. This test is described below in details.
A weight loss coupon, immersion test was used to evaluate the invention compound for its effectiveness in inhibition of naphthenic acid corrosion at 290 °C temperature.
Chemicals / Materials used :
Compounds of Example 1 is different dosages such as 200, 300 and 400 ppm were used in these experiments.
Specification of Chemicals / Materials used
Hydrocarbon oil of Grade D - 130 was distilled to remove the lower boiling fraction and the fraction having boiling point between 290 °C and 324 °C was used for testing efficiency in inhibition of naphthenic corrosion.
The detailed specifications are given below:
(i) Hydrocarbon oil (D -130) (residue after discard distillate at
290C):
PMCC = Pensky Martin Close Cup
IBP = Initial Boiling Point
FBP = Final Boiling Point
Appearance = Clear light, yellow colour liquid
Specific gravity at 32 °C = 0.8160
Viscosity at 38 °C =8.14
Flash point (PMCC) =138°C
Pour point = - 6 °C
19

IBP = 290 °C
FBP = 324 °C
Acid value = NIL
Sulphur content = (ii) Weight loss coupon:
CS = Carbon Steel
a) Material =CS 1010
b) Dimension = 76mm x 13mm x 1.6mm Diameter of hole = 5.5mm
c) Chemical analysis of coupon
Elements weight %
C 0.09
Mn 0.33
P 0.008
S 0.007
Si 0.02
Al 0.051
Cu 0.01
Mo 0.01
Sn 0.002
Sb 0.002
N 0.0031
Cr 0.02
Ni 0.01
Ti 0.002
20

(iii) Naphthenic acid;
Grade Commercial
Acid value 230 mg KOH / gm
Apparatus used
(i) Four - necked round bottom flask (one liter capacity)
(ii) Water condenser
(iii) Thermometer pocket with thermometer
(iv) Heating mental with temperature regulator
(v) N2 gas purging tube (with bottom bulb)
(vi) Rotameter for N2 gas purging
(vii) Glass stirrer rod ("S" shaped bottom)
(viii) Pipettes
(ix) Glass beaker
(x) Measuring cylinder
(xi) Glass rod (bottom bend) for holding coupons
(xii) Teflon tape
(xiii) Teflon cork

Test conditions
(i) Temperature = 290 °C
(ii) N2 gas flow rate = 110cc/min
(iii) TAN of system after adding Naphthenic acid = about 12
(iv) Product doping temperature = 100°C
(v) Time for stirring after doping = 15 minutes
(vi) Coupon passivation time = 1 hour at 290 °C
21

(vii) Immersion time of coupon in the
corrosive medium = 4 hours at
290 °C
Test Procedure:
1) 600 gm ( about 750 ml) paraffinic hydrocarbon oil (D -130) was taken in a one -liter four necked round bottom flask equipped with water condenser, N2 purger tube, thermometer pocket with thermometer and stirrer rod;
2) N2 gas purging was started with flow rate of 110 cc / min and temperature was raised to 100 °C. This temperature of 100 °C was maintained for 30 minutes deairation;
3) The inhibitor compound of the present invention that is, compound comprising Polyisobutylene and Phosphorous pentasulphide with sulphur powder was added to the reaction mixture;
4) Stirring of the reaction mixture was started and the stirring was continued for a period of 15 minutes at the temperature of 100 °C;
5) The stirrer was removed and the temperature of the reaction mixture was raised to 290 °C;
6) The pre - weighed metal coupon of weight "W1” gm, was immersed in the reaction mixture with the help of the glass rod and Teflon tape;
7) Simultaneously N2 gas flow was continued , at flow rate of 110 cc / min;
8) This condition of reaction mixture that is, N2 gas flow rate mentioned above and temperature of 290 °C was maintained for passivation time of 1 hour;
9) After one hour, naphthenic acid of weight 31 gm was added to the reaction mixture and the condition (of item 8 above) of reaction mixture was now maintained for next 4 hours;
22

10) A sample of one gm weight was collected from the reaction flask for determination of acid value; (acid value of the reaction mixture after addition of naphthenic acid = approximately 11.7);
11) After completion of the above mentioned period of 4 hours of step (9), the metal coupon was removed and cleaned by scrubbing the metal coupon with soft paper and hexane and then was dried and reweighed as having weight "W2" mg;
12) The weight loss of the metal coupon is measured as "W", wherein
W = (W, - W2) mg;
13) The general corrosion rate in MPY (mills per year) is calculated by the
formula
MPY = 534 x Weight loss in gm
(Density in gm/cc) x (Area in in2) x (Time of test in hours)
Table 1

Exper iment Sr.No. Inhibitor Dosageinppm Weightlossinmg Corrosion Rate MPY Corrosion Inhibitors Efficiency in%
1 Only metalblank(No inhibitorCompound) 89.5 524.89
2 50% active Compound of Example 1, (Polyisobutylene, Phosphorus penta sulphide and sulphur powder) and 50% solvent 200 63.3 371.23 29.27
3 Compound as per experimentNo. 2 300 39.6 232.24 55.76
4 Compound as per experimentNo. 2 400 15.2 89.114 83.02
23

EXAMPLE 3
The clean four - necked - flask was equipped with stirrer, nitrogen gas inlet and condenser. The noctanol weighing 400gms was charged in the flask. The phosphorous pentasulphide weighing 187 gms, was then added to the flask in installments. The temperature of the flask was then increased to 110 degree C. The gas H2S was seen to be evolved after addition of P2S5. After one hour, the reaction mixture in the flask was heated to 140 degree C and the flask was maintained at that temperature for one hour. The acid value of the reaction mixture was about 125 mg/KOH. This reaction mixture was then transferred to the autoclave, and ethylene oxide was added till the pressure remained constant, thereby indicating no further absorption of the ethylene oxide by the reaction mixture. The system was then purged with nitrogen gas to remove the excess of ethylene oxide. The acid value of the final product was about 25 mg/KOH.
EXAMPLE 4
Experiments were carried out by the inventor of the present invention, to test the synergetic effectiveness of a combination of the compounds (A) and (C), where compound (A) represents polyisobutylene plus phosphorous pentasulphide plus sulphur powder and compound (C) represents the resulting reaction compound when the chemical compound (B) is reacted with cyclic oxides such as ethylene oxide.
Different total dosages of inhibitor compounds' combination such as 300 ppm and 360 ppm were used in the experimentation. Similarly, different proportions of compound (A) and compound (C), were used in these experiments. The percentage proportions of (A): (C) was 50:50. The result of these experiments are presented in Table 2..
24

The results of the experiments are presented in Table 2

ExperimentNo. Compound (A) dosageIn ppm (50% wasactive) Compound (C) dosagein ppm (50 % wasactive) Ratio (A): (C) TotalDosage inppm Weight loss in mg.
1 200 200 63.3
2 300 300 39.6
3 400 — 400 15.2
4 150 150 39.6
5 180 180 21.1
6 150 150 1:1 300 8.1
7 180 180 1:1 360 0.2

25

Documents:

1769-MUM-2007-ABSTRACT(12-9-2008).pdf

1769-MUM-2007-ABSTRACT(GRANTED)-(26-7-2012).pdf

1769-MUM-2007-AUSTRALIAN DOCUMENT(29-3-2012).pdf

1769-MUM-2007-CANADA DOCUMENT(29-3-2012).pdf

1769-MUM-2007-CLAIMS(AMENDED)-(29-3-2012).pdf

1769-MUM-2007-CLAIMS(GRANTED)-(26-7-2012).pdf

1769-MUM-2007-CLAIMS(MARKED COPY)-(29-3-2012).pdf

1769-MUM-2007-CORRESPONDENCE(10-12-2008).pdf

1769-MUM-2007-CORRESPONDENCE(12-9-2008).pdf

1769-MUM-2007-CORRESPONDENCE(30-9-2011).pdf

1769-MUM-2007-CORRESPONDENCE(7-1-2010).pdf

1769-MUM-2007-CORRESPONDENCE(IPO)-(26-7-2012).pdf

1769-mum-2007-correspondence-received.pdf

1769-mum-2007-description (provisional).pdf

1769-MUM-2007-DESCRIPTION(COMPLETE)-(12-9-2008).pdf

1769-MUM-2007-DESCRIPTION(GRANTED)-(26-7-2012).pdf

1769-MUM-2007-FORM 18(10-12-2008).pdf

1769-mum-2007-form 2(12-9-2008).pdf

1769-MUM-2007-FORM 2(GRANTED)-(26-7-2012).pdf

1769-MUM-2007-FORM 2(TITLE PAGE)-(12-9-2008).pdf

1769-MUM-2007-FORM 2(TITLE PAGE)-(GRANTED)-(26-7-2012).pdf

1769-MUM-2007-FORM 3(12-9-2008).pdf

1769-MUM-2007-FORM 3(29-3-2012).pdf

1769-MUM-2007-FORM 3(30-9-2011).pdf

1769-MUM-2007-FORM 3(7-1-2010).pdf

1769-MUM-2007-FORM 5(12-9-2008).pdf

1769-mum-2007-form-1.pdf

1769-mum-2007-form-2.doc

1769-mum-2007-form-2.pdf

1769-mum-2007-form-26.pdf

1769-mum-2007-form-3.pdf

1769-MUM-2007-PETITION UNDER RULE 137(29-3-2012).pdf

1769-MUM-2007-REPLY TO EXAMINATION REPORT(29-3-2012).pdf

1769-MUM-2007-SINGAPORE DOCUMENT(29-3-2012).pdf

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Patent Number

253511

Indian Patent Application Number

1769/MUM/2007

PG Journal Number

30/2012

Publication Date

27-Jul-2012

Grant Date

26-Jul-2012

Date of Filing

14-Sep-2007

Name of Patentee

DORF KETAL CHEMICALS (I) PVT. LTD.

Applicant Address

DORF KETAL TOWER, D'MONTE STREET, ORLEM, MALAD (W), MUMBAI.

Inventors:

#	Inventor's Name	Inventor's Address
1	SUBRAMANIYAM, MAHESH	DORF KETAL TOWER, D'MONTE STREET, ORLEM, MALAD (W), MUMBAI-400 064.

PCT International Classification Number

C10L1/10,C10L1/188

PCT International Application Number

N/A

PCT International Filing date

PCT Conventions:

#	PCT Application Number	Date of Convention	Priority Country
1			NA