|Publication number||US3684687 A|
|Publication date||Aug 15, 1972|
|Filing date||Feb 2, 1970|
|Priority date||Feb 2, 1970|
|Publication number||US 3684687 A, US 3684687A, US-A-3684687, US3684687 A, US3684687A|
|Inventors||Carr Norman L, Hamilton Harry A, Schagrin Edward F|
|Original Assignee||Gulf Research Development Co|
|Export Citation||BiBTeX, EndNote, RefMan|
|Referenced by (4), Classifications (18), Legal Events (1)|
|External Links: USPTO, USPTO Assignment, Espacenet|
Aug. 15, I972 FRACTIONAI'ION OF LIGHT SULFUR-CONTAINING HYDRCCARBONS N. L. CARR ET AL 3,684,687
Filed Feb. 2., 1970 CORROSSIVE PRODUCT m 320 FORMATION D: P. 300 4 5 R 280 O. z 260 F/a/ LLI 24o g 220 SATURATION CURVE 2 WATER IN PENTANE r- 200 I 25 4: I80 k WATER IN HYDROCARBON MOLE F l I L; 2/ I 3 5 7 9 L 35 z 4 i}? 2 23 i -L Q L 25 26 24 l i U ll-l l-l2 FIG. 2 29 v v 28 INVENTORS NORMAN L. CARR HARRY A. HAMILTON EDWARD E SCHAGR/N 3,684,687 FRACTIONATIGN OF LIGHT SULFUR- CONTAINING HYDROCARBONS Norman L. Carr, Allison Park, and Harry A. Hamilton,
Natrona Heights, Pa., and Edward F. Schagrin, Sharon,
Mass, assignors to Gulf Research & Developmeent Company, Pittsburgh, Pa.
Filed Feb. 2, 1970, Ser. No. 7,671 Int. Cl. C10g 19/02 US. Cl. 208-47 7 Claims ABSTRACT OF THE DISCLOSURE This invention relates to methods for preventing the formation of corrosive hydrocarbon products. More particularly, this invention relates to methods for preventing the formation of corrosive products during thermal processing of natural of synthetic hydrocarbons containing sulfur compounds.
The art of hydrocarbon chemical production has long been cognizant of the need to remove certain sulfurcontaining compounds from hydrocarbon products in order to render them noncorrosive. These sulfur-containing compounds, hereafter referred to as corrosive sulfurcontaining compounds, are well known in the art as being inorganic sulfur-containing compounds which include elemental sulfur and hydrogen sulfide.
Various and sundry techniques have been devised by the art to eliminate a sufficient amount of these corrosive sulfur-containing compounds from the hydrocarbon products so as to render the products noncorrosive. Generally, such techniques fit into two separate categories. The first category consists of actually removing the corrosive sulfur-containing compounds from the hydrocarbon system involved. This is usually done by a monoethanol amine scrubbing treatment which is an absorptive process capable of removing indigenous corrosive sulfur-contain ing compounds from the hydrocarbon stock. The second category consists of rendering the indigenous corrosive sulfur-containing compounds passive by reaction with some other compound to form stable products. Caustic treating is an example of a second category process which is applicable for treating hydrocarbon stock containing relatively small amounts of corrosive sulfur-containing compounds. In such a process a hydrocarbon stock is washed with a caustic material such as sodium hydroxide. Although caustic washing can effectively remove corrosive sulfur-containing compounds, the process is difficult to perform on a practical basis. Accordingly, it would be more desirable to prevent the formation of corrosive sulfur-containing compounds in the first instance, particularly since elemental sulfur is usually not present in raw natural hydrocarbons.
Despite the fact that hydrocarbon products may be rendered initially noncorrosive by using one of the above described techniques, it has been found by the art that for some heretofore undefined and unexplainable reason, certain batches of these products turn corrosive with further processing. It has also been found that when the United States Patent l 3,684,687 Patented Aug. 15, 1972 corrosive sulfur-containing compounds are not initially completely removed, the corrosiveness of a hydrocarbon product can increase with further processing in a heretofore seemingly inconsistent and unexplainable manner. Since both situations, until now, have been unpredictable in nature, they have presented a very real problem to the industry as a whole.
For the above reasons, then, there exists a long-felt need in the art for a technique which will eliminate the problem as described. In this respect, it should be stated that the terms corrosion, corrosive, or the like are used herein according to their well known meaning in the art. That is to say, a particular compound or product is considered corrosive in the art of hydrocarbon production if it fails to pass the copper strip corrosion test, ASTM D1838-61T. Likewise, a compound increases in corrosiveness, if it shows an increased amount of corrosion according to this same test.
It has now been found that the above-described problems of reversion to a corrosive state and increased corrosion are most probably due to a reaction phenomenon caused by the thermal processing of a hydrocarbon prodnot containing therein at least a trace amount of a noncorrosive sulfur-containing compound which is capable of decomposing into one of the above-described corrosive sulfur-containing compounds. In most instances where the art has sought to remove corrosive sulfur-containing compounds by one of the above-described techniques, they have generally done so only to the extent of rendering the product initially noncorrosive. In almost all instances then, hydrocarbon products contain at least a trace amount (e.g. about 5 ppm.) of the potentially offending, noncorrosive sulfur-containing compounds.
Examples of these noncorrosive sulfur-containing compounds Which may be found in a typical hydrocarbon product and which may give rise to the above-described problems include: the alkanethiols (mercaptans) such as methyl mercaptan, ethyl mercaptan, n-propyl mercaptan, isopropyl mercaptan, the butyl mercaptans, and amyl mercaptans, l-heptanethiol, Z-heptanethiol, the octane, nonane, decane, undecane, tridecane, tetradecane, pentadecane, hexadecane, heptadecane, octadecane and nonadecane thiols and the eicosanethiols. Also included are the thiaalkanes, dithiaalkanes, cycloalkanethiols, aromaticthiols, thiacycloalkanes, and thiophenes.
Examples of the thiaalkanes include dimethyl sulfide, methylethyl sulfide, diethyl sulfide, methyl n-butyl sulfide, 3-thiahexane, 3-methyl-2-thiapentane and the like. Examples of the dithiaalkanes include dimethyl disulfide, diethyl disulfide, dipropyl disulfide. Examples of the cycloalkanethiols include cyclopen'tanethiol and cyclohexanethiol. An example of the aromaticthiols includes l-phenylethanethiol. Examples of the thiacycloalkanes include thiacyclobutane, thiacyclopentane, thiacyclohexane, and Z-methylthiacyclopentane. Examples of the thiophenes include thiophene, 2-methylthiophene, 3-methylthiophene, and benzo (,3) thiophene.
In view of the foregoing illustrative examples of potentially offending, noncorrosive sulfur-containing compounds, it should be noted that the organic sulfur-containing compounds, such as the sulfides and mercaptans, are not in and of themselves the cause of copper strip corrosion failure when they are present in hydrocarbons. The potentially obnoxious nature of these noncorrosive sulfur-containing compounds is characterized by their ability to decompose and form corrosive sulfur-contain. ing compounds, such as elemental sulfur and hydrogen sulfide. Apparently, it is the presence of elemental sulfur and/or hydrogen sulfide which is the fundamental cause of copper strip corrosion failure.
In accordance with the above findings, and regardless of the particular corrosive or noncorrosive sulfur-containing compounds present in a hydrocarbon product, this invention provides various techniques which may be used to eliminate the above described problems of reversion to a corrosive state and increased corrosion. Such techniques basically comprise controlling the net amount of corrosive sulfur-containing compounds formed by a reaction phenomenon which is caused by the presence of at least a trace amount of a noncorrosive sulfur-containing compound in a hydrocarbon product in a metal sulfide environment. Preferred particular techniques which may be used comprise the step of either, (1) maintaining the temperature of any thermal process in which the hydrocarbon is present below about 250 F., and/or (2) controlling the water content of the hydrocarbon phase below about 1.0 mole percent, and preferably below about 0.8 mole percent.
As illustrative of this invention, reference is made to the drawings wherein:
FIG. 1 is a graph illustrating the two-dimensional nature of controlling corrosiveness in a hydrocarbon; and
FIG. 2 is a schematic illustration of a preferred operation for preventing the porduction of a corrosive hydrocarbon product.
It has been found that the above-discussed reaction phenomenon caused by thermal processing of a hydrocarbon product containing at least a trace amount of a noncorrosive sulfur-containing compound results in the formation of corrosive sulfur-containing products, such as elemental sulfur and hydrogen sulfide. Since a hydrocarbon product containing as little as 1 or 2 ppm. of a corrosive sulfur-containing compound will fail the copper strip corrosion test, the formation of even minute quantities of corrosive sulfur-containing compounds must be avoided. In this connection, it is believed that corrosive sulfur-containing compounds are formed when the noncorrosive sulfur-containing compounds in a hydrocarbon product hydrolyze in the presence of a metal sulfide environment which acts as a catalyst. The metal sulfide environment is usually in the form of a piece of processing equipment (usually stainless or carbon steel) which comes into contact with the noncorrosive sulfur containing hydrocarbon product and which has previ ously been sulfided by former use or which becomes sulfided by contact with the noncorrosive sulfur-contain ing hydrocarbon product. In this respect, then, metal sulfide environments generally may be formed in situ or be present due to earlier formation.
The catalytic reaction which forms corrosive sulfurcontaining compounds from noncorrosive sulfur-compounds is a hydrolysis reaction heavily dependent upon both temperature and water content. Its mechanism may be schematically represented by the following reaction equations wherein the corrosive sulfur-containing compounds are designated as being elemental sulfur (S Noncorrosive S-compound metal sulfide surface catalyst S, metal metal S! metal S (desorption) As is evident from this mechanism, if the metal environment which contacts the hydrocarbon product has been previously sulfided, adsorption will not take place and a net production of corrosive sulfur-containing products, e.g. elemental sulfur (S will result. If, on the other hand, the metal environment is not completely sulfided, the corrosive sulfur-containing compounds that are formed will be used to sulfide the metal. Thus, until the metal environment becomes sulfided, little or no net corrosive sulfur-containing compounds will be produced and little or no corrosion will occur. Such a phenomenon serves to explain the heretofore upredictability of reversion to corrosion or increased corrosion of hydrocarbon products caused by various themal processes.
Upon examination thereof, the above mechanism il- 11 S; H2 other products lustrates that other variables besides temperature and water content have an effect upon the formation of corrosion sulfur-containing compounds. For example, the degree of sulfiding and the type of metal used will also affect the reaction to some degree. In practice, however, and when seeking to control the problem of copper strip corrosion, the degree of sulfiding is usually an unknown and uncontrollable variable. In addition, the type of metal equipment used is standard and thus is generally not controllable. Therefore, and although the degree of sulfiding and type of metal may theoretically be used to control corrosion, the two most practical variables which may be used to control corrosion are temperature and water content. For this reason, it has been found that the formation of corrosive sulfur-containing compounds in a hydrocarbon product during thermal processing may be adequately, practically, and effectively controlled by using one or both of the two techniques disclosed herein.
-As illustrated in FIG. 1, if a hydrocarbon product which contains at least a trace amount of a noncorrosive sulfur-containing compound (e.g., about 5 ppm.) is thermally processed at a temperature about about 250 F. while the water content of the hydrocarbon phase exceeds about 0.8 to about 1.0 mole percent, it will fail the copper strip corrosion test regardless of whether it would have passed the test prior to the thermal treatment. Of course, if the product were corrosive' before the thermal treatment, as for example where corrosive sulfurcontaining compounds had not been removed, the above discussed temperature-water content relationship is inconsequential and the product will remain corrosive regardless of the temperature of the thermal treatment or the water content in the hydrocarbon.
According to FIG. 1, then, and independent of the above findings as to the mechanism which causes corrosiveness, the corrosiveness of a hydrocarbon product which contains at least a trace amount of a noncorrosive sulfur-containing compound (e.g., above about 5 ppm.) may be controlled by either 1) maintaining the temperature of the hydrocarbon product below about 250 F., or (2) if the temperature of the product exceeds 250 F., controlling the water content of the hydrocarbon phase so that it does not exceed about 1.0 mole percent and preferably 0.8 mole percent. It is understood in this respect that the amount of 5 ppm. is merely illustrative. If it is found that smaller amounts of noncorrosive sulfurcontaining compounds as set forth above, are present and the product is becoming corrosive with thermal treatment, the techniques of this invention should be employed.
The above-described techniques for controlling the corrosiveness of a hydrocarbon product find wide practical utility throughout the chemical industry. In this respect, the term hydrocarbon product as used throughout this specification, is used in its broadest sense. That is to say, it is used to define any hydrocarbon material which is to be treated or used for a useful purpose. In this respect, then, this term refers to raw products, intermediate products, and final products alike.
One of the largest industrial areas in which these techniques find a particularly high degree of usefulness is in the natural gasoline and petroleum industries. From the time the crude petroleum is sent to the topping tower until the final products are processed and used, the various hydrocarbon products throughout the system are being thermally treated in metal equipment to effect desired results. Undue corrosiveness occurring at any point during the system can not only render a particular product unusable, but can also poison catalysts. Usually, the bulk amounts of corrosive sulfur-containing compounds are removed, as by amine scrubbing and/or caustic-washing, early in the system. However, as stated hereinabove, trace amounts of noncorrosive sulfur-containing compounds almost always remain in the system. Since even trace amounts of these noncorrosive sulfur-containing compounds may decompose and cause the hydrocarbon to fail the copper strip corrosion test, it is contemplated as a part of this invention to control the water content of the hydrocarbon and/or the temperature at which the hydrocarbons are thermally treated.
In addition, the caustic and water washes used to clean the intermediate bulk product introduce therein a saturation amount of water which may comprise up to about 0.5 mole percent. However, in certain instances the amount of water introduced into the system may exceed the saturation amount and may even exceed about 1 mole percent. For example, the water content of the washed intermediate may exceed about 1 mole percent when excess water is entrained in the intermediate leaving the wash tower or when the wash tower is otherwise malfunctioning.
Fractionation, which follows the washing steps, is generally carried out in a fractionator which is provided with one or more reboilers. These reboilers, in many instances, use temperatures which exceed 25 F. and are sulfided. Accordingly, when excessive water entrainment or a malfunction accompanies the above-discussed washing procedures, reversion to a copper strip corrosive hydrocarbon product can be expected within and throughout the fractionator system. Furthermore, even when the wash towers function properly and the water content of the wash intermediate is below about 1 mole percent, there is a significant probability that the water content of the hydrocarbon fraction in or near the reboiler of the fractionator may build up during fractionation and eventually exceed about 1 mole percent so as to cause reversion to a copper strip corrosive hydrocarbon product.
Of particular interest within the general petroleum refining system, is that portion of the system which deals with the formation of light hydrocarbons. Generally speaking light hydrocarbons are intermediate or final products of a petroleum refining system and usually include the aliphatic hydrocarbons having from 2 to carbon atoms, the aromatic and naphthenic compounds boiling within the gasoline range, or mixture of these compounds. They may be derived from natural gasoline or from any source such as thermal or catalytic cracking operations where the sulfur content, in any form, of the fraction necessitates sulfur removal before it can be marketed. In practice these light hydrocarbons are generally obtained by fractionating a bulk intermediate product containing them, which intermediate product is first caustic-washed to remove almost all of the hydrogen sulfide and mercaptans therefrom and then water-washed to remove the caustic material. The caustic washing is generally performed in a tower operating at a temperature between about 50 and 150 F., usually about 100 F., and a sufficient pressure to keep the hydrocarbon in the liquid phase. A pressure of about 50 p.s.i.g. is usually employed. An aqueous caustic solution having a concentration of from about 5% to about 30% is passed through the tower in countercurrent flow with respect to the hydrocarbon and at a caustic solution to hydrocarbon volume ratio of about 0.5:1 to 1.5 1, usually about 1:1. Although the caustic and water washes render the intermediate noncorrosive, trace amounts of noncorrosive sulfur-containing compounds almost always remain in the intermediate product. For this reason these areas of petroleum refining and natural gasoline plants are especially suited for treatment by this invention.
Using the teachings of this invention, reversion to a corrosive state during fractionation to obtain light hydrocarbons may be prevented in one preferred instance by either reducing the temperature of the reboilers below about 250 F. or removing a sufiicient amount of water from the product at some point prior to its entry into the reboilers so that the water content in the product, when in the reboiler, is less than about 1.0 mole percent and preferably less than 0.8 mole percent. In this respect, and whenever possible, reduction of temperature in the reboiler should be effected since it is more economical than effecting water removal. However, in most instances,
minimal required temperature in the reboiler must exceed 250 F. and thus removal of water will have to be used.
Removal of Wa ter prior to the product entering a reboiler may be accomplished by any conventional means known to effect this result. For example, water may be removed by the use of liquid absorbents such as triethylene glycol or solid adsorbents such as calcium chloride and various forms of alumina or silica gel. Other conventional means such as molecular sieves and the like may also be used. For a more complete summary of the numerous dehydration procedures applicable to the present in vention, one should refer to Gas Engineers Handbook, section 4, pp. 76-86, Industrial Press (1965).
Referring now to FIG. 2, there is illustrated a typical operation for producing light hydrocarbons from a raw gasoline feed, i.e., an intermediate bulk product. In the operation feed stream 1 is sent to catalytic cracker 2 which produces a raw gasoline intermediate product. This raw gasoline product, which contains large amounts of corrosive and non-corrosive sulfur-containing compounds is sent via line 3- to a water wash tower 4 where it is washed and sent via line 5 to pump 6. Exiting from pump 6, the raw gasoline product is fed through line 7 to a tower 8 wherein a caustic-Wash treatment as hereinabove described removes a suflficient portion of the corrosive sulfur-containing compounds from the raw prod not to render the raw product noncorrosive. The raw product, however, generally still contains above about 5 p.p.m. of noncorrosive sulfurcontaining compounds in the raw hydrocarbon phase and some entrained caustic. The caustic-washed hydrocarbon is then drawn from the canstic wash tower 8 via line 9 and fed into a water wash tower 10 to remove dissolved caustic. Although both the caustic wash and the water wash. are generally carried out by phase separation of the aqueous phase, drawn off at 11 and 12, from the hydrocarbon phase, drawn off at 9 and 13, a small amount of water, generally less than 1.0 mole percent, remains in the hydrocarbon phase. After leaving the water wash tower 10, the hydrocarbon phase is normally passed through line 13 toward a fractionation tower 14 wherein the hydrocarbon phase is split into two or more products streams or fractions which leave the fractionator 14 for example, through lines 15, 16 and 17. The less volatile constituents of the hydrocarbon material in the fractionator normally pass through line 18 towards a reboiler 19 wherein they are heated, generally above about 250 F., vaporized, and returned via line 20 to the fractionator.
However, as indicated above, situations often arise wherein excess water is entrained in the hydrocarbon phase or wherein the wash towers malfunction slightly so that the water content in the hydrocarbon phase leaving the wash tower 10 exceeds about 1 mole percent. When such entrainment or tower malfunctioning occurs, and when the temperature at some point in the fractionation system exceeds about 250 F., there is a need to provide the control techniques of the present invention if reversion to corrosion is to be avoided. Although the technique of temperature control may be used in certain instances, for most purposes, temperatures above 250 F. are required in at least the reboiler 19. Therefore, a conventional water-content control system may be employed to prevent reversion to corosion when the water content in the hydrocarbon phase at any point in the fractionation system exceeds about 1 mole percent.
In this regard, a suitable watercontent operative control mechanism 21 may be disposed in line 13 to selectively open either valve 22 or 23, each of which would otherwise be closed. Thus, when the Water content of the hydrocarbon stream passing through line 13 is less than about 1 mole percent, for example, at about 0.4 or 0.6 mole percent, the control mechanism 21 will open valve 23 so as to feed the washed hydrocarbon stream into a preheater 25 and then into the fractionator 14. However, when the water content of the hydrocarbon stream approaches about 1 mole percent for example, at about 0.6 or 0. 8 mole percent, the control mechanism 21 will open valve 22 so as to feed the washed hydrocarbon stream into a conventional water removal system 24, such as a molecular sieve, wherein the hydrocarbon stream is dried. The dried hydrocarbon stream is then passed through the prehea-ter 25 and into the fractionator 14. It will be appreciated that other conventional drying means may replace the molecular sieve. In the water removal system 24, there is removed sufiicient water such that the water content of the raw hydrocarbon stream entering and exiting from preheater 25 is below about 1.0 mole percent and preferably below about 0.8 mole percent. Excess water is removed from water removal system 24 by line 26. The dehydrated feed issuing from preheater 25 may then be fractionated in tower 14 and reboiler 19 with no reversion to corrosion taking place. The positioning of the water removal system at 24 is by no means critical since, depending upon the nature of the system, various other positions may be used. For example, if reboiler 19 is the only location at which temperatures exceed 250 F., a water-content operative control mechanism 27, similar to 21, may be inserted in line 18 to selectively open valve 28 or 29 which would otherwise be closed. Thus, when the water content of the hydrocarbon stream passing through line 18- toward the reboiler 19 approaches about 0.8 mole percent, control mechanism 27 will open valve 29 and direct the hydrocarbon stream to a suitable Water removal system 30 prior to reboil. Likewise, when the water content of the stream in line 18 is below about 0.8 mole percent, valve 28 will be opened and the stream will by-pass the water removal system 30.
Furthermore, since there is a likelihood that 19 will build up so as to exceed about 1 mole percent, it may be necessary to decrease the water content the hydrocarbon material contained in the reboiler 19 itself. This may be accomplished by providing a water content operative control mechanism 31 in direct fluid communication with the reboiler 19 so that the water content of the hydrocarbon material contained therein is monitored at all times. In this manner, when the water content of the material in the reboiler 19 exceeds about 0.6 mole percent, for example, the control mechanism 31 will open valve 32 so as to permit the excessively wet reboiler contents to pass through a suitable water removal system 33 and then through a suitable pumping device 34 for recycle back to the reboiler 19.
In another embodiment, the control mechanism 31 may control valves 22 and 23 as well as valve 32. In this manner, when the water content in the reboiler 19 builds up to about 0.6 mole percent, for example, the control mechanism 31 may simultaneously (1) cause the hydrocarbon stream passing through line 13 to flow through valve 22 and into the water removal system 24, even though the water content thereof may be substantially below 1 mole percent, and (2) cause the hydrocarbon material in the reboiler 19 to flow through valve 32 and into the water removal system 33. This will effect a rapid decrease in the water content of the hydrocarbon stream in the reboiler, since it will remove the water directly from the hydrocarbon material in the reboiler and from the fractionator feed as well.
The above-described fractionating system comprises one preferred technique as contemplated by this invention. However, in situations wherein it is possible to fractionate at temperatures below about 250 F., such lower temperatures should be employed. Moreover, in situations which involve the separation of higher boiling hydrocarbons, i.e., those which normally require fractionator or reboiled temperatures in excess of about 250 =F., it may prove feasible to conduct the separation at sub-atmospheric pressures as a means for maintaining the fractionator and/or reboiler temperature below 250 F. without adversely affecting the desired separation of the hydrocarbons. As illustrated in FIG. 2, one way of controlling the pressure in the fractionator is to dispose a steam enjector 35 in fluid communication therewith.
Once given the above disclosure, many variations thereof will become apparent to one skilled in the art. For example, this invention is broadly applicable to corrosion control generally. It is not necessarily limited to eliminating the reversion to a corrosive state of a noncorrosive hydrocarbon product which contains very small amounts of noncorrosive sulfur-containing compounds nor to eliminating the increase of corrosiveness of a hydrocarbon product which contains relatively large amounts of corrosive and noncorrosive sulfur-containing compounds. This is due to the fact that, in certain instances, corrosion control of a corrosive material is all that is desired or necessary.
The following examples serve to further illustrate this invention, it being understood that they are not limitations thereon.
EXAMPLE 1 A standard commercial hydrocarbon product and a typical sulfided fractionator were precisely simulated in the following manner:
Phillips technical grade n-pentane (969 F. boiling point) was caustic washed, water washed, dried over 4A sieves, and deoxygenated by nitrogen agitation. To diiferent portions of the pentane there were then added various amounts of mercaptans as indicated in the further examples which hereinafter follow, in order to simulate standard commercial products of n-pentane.
Several stainless steel reaction vessels (Hoke Catalog No. 4LS75) having a capacity of 75 ml. were sulfided in the following manner. Into each vessel there was placed 0.5 gram of sulfur. Each vessel was then heated overnight at 800 F. and for an additional one hour at 1000 F. Free, unreacted sulfur which remained in each vessel after the heat treatment was removed by successive carbon disulfide, naphtha, and acetone washes until the acetone wash was sulfur free. The thus-prepared vessels accurately simulated a metal sulfide environment that might be found, for example in a typical fractionator as shown and described with respect to FIG. 2. Since the vessels aged during use in the following reported examples, the abovedescribed sulfiding procedure was repeated when standard experiments indicated that the sulfided interior of each vessel was no longer active or effective. In addition, as the vessel aged, auxiliary treatments, such as soaking the interior surface with 1000 p.p.m. ethyl mercaptan at 260 F. were used when necessary to reactivate the vessels to be used in further examples.
All of the following examples were conducted under suflicient pressure to insure the presence of a liquid phase.
EXAMPLE 2 The following example illustrates the corrosiveness of elemental sulfur when present in a hydrocarbon product.
To 5 separate portions of the pentane product prepared in Example 1 there were added the following amounts of elemental sulfur:
AS'lM Dl838-61T, only a 1-A rating indicates a noncorrosive hydrocarbon product. All other ratings are considered corrosive, in the increasing degree as indicated by both letter and number Le. 13 is more corrosive than 1A but less corrosive than 2C, 2D and 4A in that order of increasing corrosiveness.
2 This test indicates that the standard pentane product prepared in Example 1 is noncorrosive.
9 EXAMPLE 3 Various portions of the standard pentane product prepared in Example 1 were spiked with 100 ppm. of ethyl mercaptan, and separately heated as indicated in the sulfided stainless steel vessels prepared in Example 1. The pentane, though spiked was initially noncorrosive prior to heating. The following table sets forth the results:
As indicated by ASTM 1838-611, wherein any rating greater than LA is considered corrosive.
EXAMPLE 4 A carbon steel reaction vessel was sulfided according to the procedure of Example 1. A portion of the standard pentane product of Example 1 was spiked with about 50 p.p.m. of ethyl mercaptan, saturated with water (he. sufficient water to saturate the mixture of 260 F.), and passed through the vessel for about 8 hours. The vessel was heated sufiiciently to raise the temperature of the pentane mixture to about 260 F. No corrosive products were obtained during the treatment. However, when the operation was shut down at the end of the day by turning off the heaters and isolating the system overnight, the contents of the sulfided vessel turned corrosive. The next morning the carbon steel vessel and its lines were thoroughly polluted with corrosive material; and when the flow treatment was again resumed the pentane mixtures rapidly attained a corrosive rating at room temperature. Although each part of the unit was washed successively with carbon disulfide, naphtha, and acetone until the acetone washings were sulfur free, the unit was found to be contaminated when put into operation. Consequently, the clean-up operation had to be repeated a second and a third time.
As indicated by this example, the presence of corrosive contaminants in processing equipment has a lasting effect on subsequent processing; and considerable effort is required to remove trace contaminant materials. As also indicated by this example, the corrosiveness of a hydrocarbon product may not evidence itself immediately, but may only occur after some finite period of time following a thermal treatment. This, of course, is explanable by the above reaction mechanism whereby chemisorptionedesorption may take a finite period of time to occur.
The above experimental procedure was again followed in a separate sulfided carbon steel reaction vessel except that the amount of water present in the pentane mixture was limited to about 0.7 mole percent. No corrosion occurred even after standing for about two days.
EXAMPLE A procedure similar to that set forth in Example 4 was followed except that instead of using ethyl rnercaptan as the spike, several runs were made using various other organic sulfur-containing compounds. Compounds added in the amount of 50 p.p.m., were dimethyl sulfide and dimethyl disulfide. When heated for eight hours at 260 F. without adjusting the water content to a level below 10 about 1.0 mole percent the product turned corrosive upon standing overnight. When the water content was controlled to below 0.8 mole percent, the product remained noncorrosive even after standing for about 36 hours.
Once again the above disclosure various other features and modifications Will become apparent to those skilled in the art. Such features and modifications are, therefore, contemplated by the present invention and included within the spirit and scope thereof.
1. A process for controlling the corrosiveness of a caustic washed hydrocarbon product having from 2 to 10 carbon atoms per molecule and containing at least a saturation amount of water and at least 5 parts per million of a non-corrosive organic sulfur-containing compound, wherein the hydrocarbon is subjected to a thermal treatment in a metal sulfide environment which comprises:
controlling the amount of water in the caustic-washed hydrocarbon to less than 1 mole percent; and then distilling the caustic-washed hydrocarbon into separate noncorrosive fractions.
2. A process according to claim 1 wherein the amount of water is controlled so as to be less than about 0.8 mole percent.
3. A process for the prevention of formation of copperstrip corrosion products caused by the thermal treatment of caustic washed hydrocarbons having from 2 to 10 carbon atoms per molecule containing at least a saturation amount of water and at least 5 parts per million of a noncorrosive organic sulfur-containing compound at a temperature of about 250 F. which comprises adjusting the water content of the hydrocarbons to less than about one mole percent prior to subjecting said hydrocarbons to temperatures in excess of 250 F.
4. A process according to claim 3 wherein said thermal treatment comprises the fractionation of a mixture of light hydrocarbons into individual light hydrocarbon products.
5. A process according to claim 3 wherein the amount of water is controlled so as to be less than about 0.8 mole percent.
6. A process which comprises:
subjecting a sour hydrocarbon having from 2 to 10 carbon atoms per molecule to treatment with an aqueous caustic solution to produce a. product which is noncorrosive but which contains at least 5 parts per million of a non-corrosive organic sulfur-containing compound;
removing said aqueous caustic solution from contact with said hydrocarbon and controlling the amount of water in said non-corrosive product to less than one mole percent;
and thereafter subjecting said hydrocarbon product to thermal treatment in a metal sulfide environment to distill the caustic washed hydrocarbon into separate non-corrosive fractions.
7. A process according to claim 6 wherein the amount of water is controlled so as to be less than about 0.8 mole percent.
References Cited UNITED STATES PATENTS 2,711,990 6/ 1955 Campbell 208263 2,589,114 3/1952 Murray 208-l87 3,071,541 1/1963 Stenzel 208-263 3,180,821 5/1965 Pfeifer 208-l87 3,591,652 7/1971 Larsen 260-677 2,035,449 3/1936 Archibald et a1. 260-677 HERBERT LEVINE, Primary Examiner U.S. Cl. X.R. 208-187, 203
mg? I UNITED STATES PATENT OFFICE CERTIFICATE OF CORREGTION Patent No. 4,687 I Dated August 15 1972 Norman L. Carr, Harry A. Hamilton Inventor(s) and- Edward F. Schagrin It is certified that error appears in the above-identified patent and that said Letters Patent are hereby eon-acted as shown below: 7
Col. 1, line 2-9, "natural of synthetic" should read -natural or synthetic-;
Col. 4, line 22 "about about" should read -above about- Signed and sealed this 30th day of January 1973 (SEAL) Attest:
EDWARD MFLETCHER R. ROBERT GOTTSCHALK Attesting Officer Commissioner of Patents
|Citing Patent||Filing date||Publication date||Applicant||Title|
|US4855035 *||Sep 14, 1988||Aug 8, 1989||Shell Oil Company||Method of abating corrosion in crude oil distillation units|
|US5264187 *||Sep 3, 1991||Nov 23, 1993||Phillips Petroleum Company||Treatment of hydrocarbons|
|US5552085 *||Oct 3, 1995||Sep 3, 1996||Nalco Chemical Company||Phosphorus thioacid ester inhibitor for naphthenic acid corrosion|
|US5630964 *||May 10, 1995||May 20, 1997||Nalco/Exxon Energy Chemicals, L.P.||Use of sulfiding agents for enhancing the efficacy of phosphorus in controlling high temperature corrosion attack|
|U.S. Classification||208/47, 208/187, 208/203|
|International Classification||C07C7/11, C07C7/04, B01J19/02, C07C7/00, C10G7/00|
|Cooperative Classification||C10G7/00, C07C7/04, B01J19/02, C07C7/005, C07C7/11|
|European Classification||C07C7/00C, C07C7/04, B01J19/02, C10G7/00, C07C7/11|
|May 5, 1986||AS||Assignment|
Owner name: CHEVRON RESEARCH COMPANY, SAN FRANCISCO, CA. A COR
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST.;ASSIGNOR:GULF RESEARCH AND DEVELOPMENT COMPANY, A CORP. OF DE.;REEL/FRAME:004610/0801
Effective date: 19860423
Free format text: ASSIGNMENT OF ASSIGNORS INTEREST;ASSIGNOR:GULF RESEARCH AND DEVELOPMENT COMPANY, A CORP. OF DE.;REEL/FRAME:004610/0801