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Publication numberUS3322664 A
Publication typeGrant
Publication dateMay 30, 1967
Filing dateJun 26, 1964
Priority dateJun 26, 1964
Publication numberUS 3322664 A, US 3322664A, US-A-3322664, US3322664 A, US3322664A
InventorsPaterson Norman J, Sullivan James N
Original AssigneeChevron Res
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Method of removing calcium sulfate from a hydrocarbon feed stock
US 3322664 A
Abstract  available in
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Claims  available in
Description  (OCR text may contain errors)

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Patented May 3%, 1967 Introduction The present invention relates to thermal cracking, visbreaking and delayed coking processes, hereinafter referred to as thermal conversion processes, more particularly to such processes wherein thermal crackers, visbreakers and delayed cokers, hereinafter referred to as thermal conversion units, are used that embody furnace tubes that are subject to fouling during process operation by various components of various hydrocarbon feeds, and more particularly to a method for reducing such fouling.

The thermal cracking processes to which the present invention relates includes thermal cracking that occurs in furnace tubes of preheaters used in preheating hydrocarbon feeds to other processes such as catalytic cracking and thermal hydrocracking. Accordingly the term thermal conversion units as used herein includes all such preheaters containing furnace tubes subject to fouling during process operation caused by or aggravated by hydrocarbon conversion occurring in such preheaters.

Coking of furnace tubes of thermal conversion units It is well known that various impurities from many different types of hydrocarbon feed stocks tend to deposit on the inner surfaces of the aforesaid furnace tubes and thereby contribute to increased fouling thereof by deposition of carbonaceous deposits thereon with resulting reduction in hydrocarbon conversion and in duration of on-stream periods.

Prior art methods combatting fouling of thermal conversion unit furnaces tubes Heretofore it has been recognized that the presence of sodium chloride in hydrocarbon fractions fed to thermal conversion units has contributed to fouling of the furnace tubes of said units by making available at the inner surfaces of the tubes sodium chloride nuclei around which carbon deposits can form at a rate that is greater than in the absence of such nuclei. Accordingly, various desalting procedures for the removal of sodium chloride from hydrocarbon feed stocks that have been used have had in part as a purpose the reduction of furnace tube fouling. However, the results of desalting procedures for the removal of sodium chloride, while extremely effective for other purposes, in many cases have not included sufficient reduction in furnace tube fouling. It has been recognized that hydrocarbon feed stock contaminants other than sodium chloride might play a part in accelerating furnace tube fouling; however, heretofore there has been little or no agreement in the art as to which contaminants might be a major cause of furnace tu'be fouling. It has been observed that fouling rates have varied from time to time during process operation as feed stock character, process operating conditions and other factors have varied; however, because of the multitude of possible variables it has not been possible to date to pinpoint any one variable as a major cause of the observed fouling. Accordingly, the prevalent current refinery practice is to shut down thermal conversion units periodically when the furnace tubes thereof have become so fouled as to make continued operation so inefficient as to be economically prohibitive, for the purpose of expensive and time consuming cleaning from the furnace tubes of the accelerated carbonaceous deposits.

Objects In view of the foregoing it is an object of the present invention to provide a method for substantially reducing the rate at which furnace tubes of thermal conversion units foul during process operation by deposit of carbonaceous materials therein.

Statement of invention In accordance with the present invention calcium sulfate has been recognized as a major cause of fouling of furnace tubes of thermal conversion units during process operation. In accordance 'with the present invention there is provided a process for removing calcium sulfate from a hydrocarbon feed stock which comprises forming an intimate mixture of said feed stock with an aqueous solution, capable of dissolving calcium sulfate, of a watersoluble inorganic salt whereby said calcium sulfate is dissolved in said solution, and separating a relatively calcium sulfate-free hydrocarbon feed stock from said mixture.

Still further in accordance with the present invention there is provided a process for removing calcium sulfate from a hydrocarbon feed stock which comprises intimately contacting said feed stock with an aqueous solution, capable of dissolving calcium sulfate, of a water-soluble inorganic salt whereby said calcium sulfate is dissolved in said solution, separating at least a major portion of said solution containing dissolved calcium sulfate from said hydrocarbon feed stock, contacting the resulting hydrocarbon feed stock from which said calcium sulfate-containing solution has been removed with fresh water to dissolve any residual water-soluble inorganic salt contained in said resulting hydrocarbon feed stock and separating water and any water-soluble inorganic salt dissolved therein from said resulting hydrocarbon feed stock to produce a final hydrocarbon stock having a substantially lower content of calcium sulfate than the original feed stock.

Feeds to which the present invention is applicable The present invention is applicable to those feed fractions which when processed in a thermal conversion unit contribute to severse fouling of the furnace tubes of said unit by causing a high rate of carbon deposition on the inner walls of said tubes. In accordance with the present invention all such feed fractions contain calcium sulfate in varying amounts. Such furnace tube fouling is particularly excessive and severe during processing in thermal conversion units of calcium sulfate containing residual petroleum fractions, shale oils, tar sand oils and tar oils produced by the low temperature carbonization of coal. Various types of calcium sulfate containing petroleum residua that are particularly troublesome in this respect include residua produced from San Joaquin Valley crudes such as Belridge, San Ardo, Midway and Kern crudes, and vacuum residua from such parafiinic crudes as Four Corners and certain Mid-Continent and Texas crudes. The process of the present invention is applicable to the treatment of all calcium sulfate containing feed stocks of the aforesaid descriptions.

Conventional refinery primary distillation procedures In conventional refinery practice crude oil is processed in primary distillation facilities to obtain various fractions for further processing. The crude oil generally s heated to about 600725 F. and flashed into an atmospheric distillation tower where products such as light and heavy naphthas, kerosene and light gas oil are recovered as distillates. The atmospheric bottoms are further heated and discharged into a vacuum column wherein heavy vacuum gas oils are recovered as distillates and a short vacuum residuum is recovered as a bottoms fraction. It is conventional practice to catalytically crack the vacuum gas oils to increase the yield of gasoline in the refinery. The catalytic cracker may operate at conversions (D-i-L) of 45-85%.

Conventional thermal conversion processing of vacuum residua fractions It is customary, particularly in California refineries, to subject the vacuum residuum to additional processing in order to obtain additional gasoline production and to reduce the preduction of residual fuel oil. From California 15-30 API gravity crude oils the vacuum residuum may constitute 15-50% of the original crude. The vacuum residuum may constitute 15-50% of the original crude. The vacuum residuum may be visbroken in a once-through thermal coil to produce a small amount, for example 5- of gasoline, and the remaining visbroken bottoms product that can be blended to fuel oil specifications with considerably less light gas oil or cutter stock than would have been required by the original vacuum residuum.

Alternatively, the vacuum residuum may be mixed with 19-60% of light and heavy catalytic cycle oil and thermally cracked in a conventional single or two-coil recycle cracking unit to produce -35% of 400 F. endpoint gasoline and a residual cracked tar that is blended with light cutter stock to produce specification fuel oil.

Alternatively, the feed to the thermal cracker may be a long residuum from the bottom of the atmospheric tower. The feed to the thermal cracker is generally controlled to a viscosity of 125-3500 Saybolt Seconds Fural at 122 Frlf this is desired to eliminate production of fuel oil entirely the vacuum or atmospheric residuum may be processed in a coking unit of the delayed or fluid type wherein the feed stock is rapidly heated in a tubular furnace to incipient cracking temperature of about 900-925 F. for a short time and then coked in a coke drum to produce solid coke and distillate products having a higher hydrogen to carbon ratio than the feed.

In another application, the residuum may be the feed to a moving bed catalytic cracking unit. In this instance, the residuum is heated to 750-850 F. in a tubular furnace and flashed into a tar separator wherein the overhead vapor is the vapor feed to a moving bed catalytic cracking unit and in certain instances the bottoms is the liquid feed to said catalytic cracking unit.

In another application, the residuum is a feed to a thermal hydrocracking unit wherein a mixture of residuum and hydrogen are heated in a tubular furnace to 700- 950 F. and higher and wherein the tube diameter, feed rate or hydrogen rate, are adjusted to give a so-called turbulence level greater than 25 which corresponds to a Reynolds number greater than 11000. Said turbulence level is represented by the ratio of the average apparent viscosity of the flowing stream to the molecular or kine matic viscosity.

In still another application, the residuum is a feed to a gasification unit wherein the residuum in dispersed in steam and partially oxidized to form carbon monoxide and hydrogen as the major reaction products. In this common step, the residuum is reacted in a tubular heater with steam and free carbon and preheated to 750 F. and above and passed to the generator where it undergoes partial oxidation to hydrogen and carbon monoxide.

Conventional refinery desalting procedures for sodium chloride removal There is strong evidence that most of the salt in crude oil as produced at the well head is contained in small droplets of water dispersed throughout the crude oil. Depending upon production and shipping practices, varying amounts of particulate salt are formed through water evaporation. When the crude oil is reduced to a long or short residiuum in the refinery primary distillation facilities, dehydration occurs and the salt is left behind in particulate form. The literature describes many methods for determining the salt content of crude oils. The majority are based on an extraction step followed by the determination of the chloride ion. Other methods are based on the measurement of the conductivity of an aqueous extract (ASTM Standards for Petroleum Products and Lubricants, 40th ed., December 1963).

Conventional desalting practices used by refineries to desalt the crude oil prior to distillation include use of processes wherein the preheated crude is emulsified with .05 to .20 volume of fresh water followed by separation under pressure of the oil and water layers. To aid in the rapid separation of the oil and aqueous phases it is conventional practice to add chemical demulsification compounds and/or subject the emulsion to a high voltage silent discharge. Likewise, it is common practice to add phenolic waters to the crude oil at this point to aid in the demulsification and as a means of disposing of the phenols by solution in the crude oil and thus prevent the pollution of natural waters. Under these conditions, the water droplets coalesce and precipitate.

Sodium chloride content of feeds after conventional desalting procedures for sodium chloride removal It is conventional practice to desalt the crude oil by means of the above described desalting procedures to less than 5 pounds of salt, measured as sodium chloride, mr 1000 barrels of crude oil.

Calcium compound content of feeds and of vacuum residua fractions thereof During periods when the residua from the various crudes have been processed in thermal conversion units and excessive coking has been observed in the thermal conversion unit furnace tubes, the sodium chloride content of the desalted crude being supplied to the refinery primary distillation facilities has been below 5 pounds, measured as sodium chloride, per 1000 barrels of crude as described above. However, it has been discovered that at the same time the calcium content of the crudes being supplied to the primary distillation facilities during these severe coking periods has been in the range of 2-70 p.p.m. In turn, the calcium content of the residuum fractions supplied to the thermal conversion units has been as high as 50-190 p.p.m. The following are representative calcium analyses of various crudes prior to primary distillation, and of various vacuum residua prepared as feeds for thermal conversion units:

Calcium determination on various crudes Ca, p.p.m. Alaskan crude 2 Midway light crude 10 San Ardo crude 25 Belridge crude 63 Kern crude 24 Calcium determination on various residua feeds to thermal conversion units Ca, p.p.m. San Ardo vac. resid. 53 Belridge vac. resid Kern vac. resid. 67

In accordance with the present invention the normal run length of a thermal cracker prior to enforced shutdown because of fouling of the furnace tubes thereof can be extended from 14 days when the thermal cracker is supplied with a vacuum residuum containing 40 p.p.m. calcium sulfate to 60 days with a vacuum residuum containing 14 p.p.m. calcium sulfate. In accordance with the present invention the calcium sulfate content of the feed fractions being supplied to a thermal conversion unit preferably are reduced to less than 25 ppm. and still more preferably, less than 15 p.p.m. before they are passed to the thermal conversion unit.

Source 0 feed calcium compound content Crude petroleum is produced from formations which are sedimentary beds or strata sufficiently homogeneous to be regarded as a unit. Along with the crude petroleum, fluids such as gas and water and in many cases salt Water or brine may be found distributed throughout the formations or only in intervals or zones of the formation. Although a formation may be substantially homogeneous in composition, there are formations that vary transversely in permeability. Where the variations in formations are relatively thin they are referred to as streaks. Thus many formations may contain zones of sodium chloride interspersed in which may be streaks of calcium sulfate. When crude oil is produced along with large quantities of brine, in many instances calcium sulfate, being more soluble in brine than in fresh water will be dispersed throughout the crude oil along with the brine. Although it is conventional producing practice to separate most of the brine or water from the crude before pipeline delivery to the refinery, this separation is usually only a gravity type of operation at slightly elevated tempera tures. Thus there is considerable sodium chloride and calcium sulfate dispersed as small deposits of Water solution throughout the oil. When this crude is treated in the refinery with emulsification with fresh water, this dissolves the sodium chloride but leaves the calcium sulfate suspended in the oil since it was more soluble in brine than fresh water.

In addition to the contamination of the crude oil by impurities from the reservoir strata, it is well known in the art to increase the productivity of subsurface formations penetrated by oil and gas wells by a technique such as the well known formation fracturing. The fracturing fluid in many cases contains a mixture of oil soluble calcium soaps and calcium sulfate suspended in a crude oil or crude oil residuum as the fracturing fluid (U.S. Patent 2,997,441). In addition, it is well known to use oil Well drilling fluids Which have an oil base and containing a mixture of heavy oil and calcium sulfate (U.S. Patent 2,953,525) and are used to form an impervious mud sheath on the Walls of the drilling Well in order to cement off water and gas from various formations While drilling to the desired formations. Thus in newly drilled Wells and reconditioned older wells prepared by formation fracturing there is contamination of the crude by calciumcontaining compounds as Well as from subterranean deposits of these compounds that are solutized by oil Well brines.

Nature of calcium compounds in feed, in vacuum residua fractions thereof, and in furnace tube coke Calcium is observed in residuum feeds prepared for thermal conversion units as inorganic crystals. Examinations of these crystals have identified calcium sulfide, calcium sulfate and calcium carbonate. The only source of calcium crystals in the residuum is believed to be the inorganic calcium crystals in the original crude.

Inspections of the furnace coke from a number of thermal cracker runs that were shutdown prematurely due to coking has shown that the coke is present as a myriad of calcium particles namely, the sulfide, sulfate and oxide embedded in a matrix of coke.

Relationship between feed sodium chloride content, calcium compound content, and coking 0 thermal conversion unit furnace tubes While there are many other factors that enter into the length of run on a thermal cracker or visbreaker or delayed coker furnace, such as variations in feed type and viscosity, nevertheless the presence of high calcium content feed stocks has led consistently to short run lengths due to furnace coking. Another feature that has been noted is that the highest concentration of calcium deposits in the furnace tubes occur at those points of highest heat density-i.e. moke moke in the last 20 tubes where the temperature is the highest-910-9l5 F., maximum cracking takes place and maximum vaporization of feed.

Conventional refinery desalting procedures for the removal of sodium chloride from hydrocarbon feed stocks are ineffective for the removal of calcium sulfate because of the insolubility of the latter in water. Accordingly, a reduction in sodium chloride content of crude hydrocarbon feeds to conventional levels of 5 pounds of sodium chloride per 1000 barrels of crude does not result in a concomitant reduction of calcium sulfate. While some workers in the field have felt that calcium sulfide may be a factor contributing to fouling of furnace tubes of thermal conversion units this is not believed to be so. Calcium in the form of calcium oxide (hydrated lime) or dry calcium hydroxide has been used extensively in ther mal cracking operations to control corrosion from hydrogen sulfide and concomitantly to permit higher cracking temperatures with resulting increased conversion. In these cases calcium oxide has been added as a slurry in the feed stock charged to a thermal cracking unit in amounts equal to 0.50-0.75 pound of calcium oxide per barrel of feed. (U.S. Patents 1,580,710, 1,913,619, 2,031,336.) In this operation the calcium oxide acts as a scouring agent to remove carbon from the heated surfaces, a coagulant for heavy polymerized incipient coke precursors and as an obsorbent to carry heavy polymerized coke particles out of the system Where they are separated from the cracked tar. The calcium oxide is converted during the operation to calcium sulfide which is recovered from the process in admixture with calcium hydroxide. Particularly because of this type of operation it is not believed that calcium sulfide is a serious cause of fouling in furnace tubes of thermal conversion units. Nor is it believed that calcium carbonate contributes in any substantial degree to such fouling.

Accordingly, pursuant to the present invention calcium sulfate is removed from hydrocarbon feed stocks by steps in addition to those steps conventionally used for removing sodium chloride from hydrocarbon feed stocks, the latter steps being inadequate to obtain the necessary calcium sulfate removal.

Suitable water-soluble inorganic salts for use in the process of the present invention The water-soluble inorganic salt that is used in the process of the present invention may be any watersoluble inorganic salt or mixture of such salts, in an aqueous solution of which calcium sulfate is soluble, but preferably is a chloride or mixture of chlorides. Preferably the water-soluble inorganic salt is selected from the group consisting of sodium chloride, ammonium chloride and potassium chloride, with sodium chloride being preferred.

A sodium chloride solution is preferred in the process of the present invention compared with a solution of ammonium chloride or potassium chloride because of its cheapness, availability and ease of handling from a corrosion standpoint, even though ammonium chloride, for example, will dissolve about 30% more calcium sulfate in a saturated solution than will sodium chloride.

While NH Cl will dissolve about 30% more calcium sulfate in a saturated solution compared to sodium chloride, the cost, corrosiveness and availability makes the sodium chloride the preferred salt for commercial use.

Detailed description of process of invention Referring now to the drawing there shown is an exemplary arrangement of process operating units and fiow paths suitable for use in carrying out the process of the present invention. A preheated hydrocarbon feed containing calcium sulfate is passed through line 1 to mixing zone 2 which may be a conventional mixing valve where it is contacted with brine entering mixing zone 2 through line 3. The brine entering through line 3 preferably is a completely saturated solution of sodium chloride although good results still may be obtained if the solution is not completely saturated. Nevertheless, it is preferable that it be highly saturated to an extent of at least 80% saturation. The resulting intimate mixture of hydrocarbon feed and brine is passed through line 4 to settling zone 5 where calcium sulfate containing brine settles out from the mixture and is passed through line to brine-calcium compound separator 11 from which brine may be returned to mixing zone 2 through line 12.

The brine-calcium compound separator 11 may contain any conventional zeolite type or other type material adapted to accomplishing separation of the calcium compound from the brine. The material may be regenerated periodically in a conventional manner to remove adsorbed or occluded calcium compound.

From zone 5 the hydrocarbon feed from which calcium compound has been removed is passed through line 13 to mixing zone 14 which may be a conventional mixing valve where it is contacted with fresh water entering mixing zone 14 through line 15. The resulting intimate mixture is passed through line to settling zone 21 where water and sodium chloride dissolved therein settle and are passed as a solution through line 22 to tank 23, from where it may be discarded through line 24. If desired, all or any portion thereof may be recycled to mixing zone 14 through line 25. The desalted hydrocarbon feed, now having a reduced content of sodium chloride and calcium sulfate, is passed from zone 21 through line to atmospheric column 31 where it is separated into various side cuts that may be withdrawn through lines 32, 33 and 34 and a bottoms fraction which is passed through line 35 to vacuum column 36. From vacuum column 36 various side cuts may be withdrawn through lines 37, 38 and 39 and a vacuum residuum is passed through line 40 to thermal conversion unit 45. Eifiuent from thermal conversion unit is passed through line 46 to a separation zone 47 where it may be separated into various desired fractions that may be withdrawn through lines 48, 49 and 50. In both settling zones 5 and 21, the separation of oil and aqueous solutions may be facilitated by the use of demulsifying agents and/or a high voltage silent discharge.

From the foregoing it may be seen that the deleterious effect of calcium sulfate in accelerating formation of carbonaceous deposits on the inner surfaces of furnace tubes of thermal conversion units can be avoided by removing the calcium sulfate with a saturated or highly saturated brine to dissolve finely dispersed particles of calcium sulfate, and that the excess sodium chloride or brine solution can be removed with fresh water. The removal of the calcium sulfate may be accomplished either in the field or at the refinery, and operation in accordance with the process of the present invention may be integrated with conventional refinery desalting facilities for the removal of sodium chloride from hydrocarbon feed stocks. With the elimination of calcium sulfate, which in high temperature zones can crystallize out of solution and form insoluble crystals of hydrate on heated surfaces, such crystals will not be available at the heated surface to serve as nuclei to collect heavier polymers or coke precursors which cause carbonaceous fouling. The brinecalcium compounds separator 11 may contain a zeolite exchange resin on which calcium is deposited, with sodium ion being exchanged in its place. Alternatively, the calcium may be precipitated in a batch process from the brine solution by addition of sodium carbonate, phosphate or other salt that will precipitate the calcium as calcium carbonate or phosphate etc. which can be allowed to settle and can be drawn off and discarded.

Preferably the brine solution which is passed through line 3 will be at a pH of about 9-l0 and the water wash which is passed through line 15 will be at a pH of about 5-6. Sodium carbonate resulting from the exchange in zone 11 will be contained in the brine in line 12 which will tend to raise the pH of the total quantity of brine entering mixing zone 2.

We claim:

1. A process for removing calcium sulfate from a hydrocarbon feed stock which comprises forming an intimate mixture of said feed stock with an aqueous solution, capable of dissolving calcium sulfate, of a watersoluble inor anic salt, whereby said calcium sulfate is dissolved in said solution, and separating a relatively calcium sulfate-free hydrocarbon feed stock from said mixture.

2. A process as in claim 1, wherein said water-soluble inorganic salt is a chloride.

3. A process as in claim 2, wherein said water-soluble inorganic salt is selected from the group consisting of sodium chloride, ammonium chloride and potassium chloride.

4. A process for removing calcium sulfate from a hydrocarbon feed stock which comprises intimately contacting said feed stock with an aqueous solution, capable of dissolving calcium sulfate, of a water-soluble inorganic salt, whereby said calcium sulfate is dissolved in said solution, separating at least a major portion of said solution containing dissolved calcium sulfate from said hydrocarbon feed stock, contacting the resulting hydrocarbon feed stock from which said calcium sulfate-containing solution has been removed with fresh water to dissolve any residual water-soluble inorganic salt contained in said resulting hydrocarbon feed stock and separating water and any water-soluble inorganic salt dissolved therein from said resulting hydrocarbon feed stock to produce a final hydrocarbon stock having a substantially lower content of calcium sulfate than the original feed stock.

5. A process as in claim 4 wherein said solution containing dissolved calcium sulfate is treated to separate said calcium sulfate therefrom.

6. A process as in claim 4 wherein at least a portion of said final hydrocarbon stock is passed to a thermal conversion unit.

7. In a hydrocarbon conversion process wherein a hydrocarbon feed stock containing at least one hydrocarbon fraction to be processed in a thermal conversion unit contains calcium sulfate that contributes to fouling of the furnace tubes in said thermal conversion unit during operation thereof, the method of reducing the fouling of said furnace tubes which comprises removing a substantial quantity of calcium sulfate from said hydrocarbon feed stock prior to passage of any fraction thereof to said thermal conversion unit by contacting said feed stock with an aqueous solution, capable of dissolving said calcium sulfate, of a water-soluble inorganic salt to dissolve said calcium sulfate, removing said solution containing dissolved calcium sulfate from said feed stock to produce a resulting feed stock containing at least one fraction suitable as a feed for a thermal conversion unit and having a reduced tendency to foul the furnace tubes of said unit and passing said fraction to said unit.

References Cited UNITED STATES PATENTS 9/1952 Coons 208- 1/1957 Powell 208-90

Patent Citations
Cited PatentFiling datePublication dateApplicantTitle
US2611735 *Jun 21, 1947Sep 23, 1952Sinclair Refining CoProcess for removing metals from crude petroleum oils
US2778777 *Feb 16, 1954Jan 22, 1957Texas CoRemoval of metal components from petroleum oils
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US4778589 *Aug 28, 1986Oct 18, 1988Chevron Research CompanyDemetallization of petroleum crudes, shale oil, liquified coal, tar sand effluent and similar oils and residues
US4778590 *Aug 28, 1986Oct 18, 1988Chevron Research CompanyDecalcification of hydrocarbonaceous feedstocks using amino-carboxylic acids and salts thereof
US4778592 *Aug 28, 1986Oct 18, 1988Chevron Research CompanyDemetalation of hydrocarbonaceous feedstocks using amino-carboxylic acids and salts thereof
US4789463 *Aug 28, 1986Dec 6, 1988Chevron Research CompanyAqueous solution extraction and separation from petroleum crudes
US4889614 *May 9, 1989Dec 26, 1989Betz Laboratories, Inc.Methods for retarding coke formation during pyrolytic hydrocarbon processing
US5271841 *Aug 24, 1992Dec 21, 1993Betz Laboratories, Inc.Method for removing benzene from effluent wash water in a two stage crude oil desalting process
US7497943Aug 27, 2003Mar 3, 2009Baker Hughes IncorporatedCompounds can be removed or transferred from a hydrocarbon phase to a water phase in an emulsion breaking process by using a composition that contains water-soluble hydroxyacids. Suitable water-soluble hydroxyacids and salts with mineral
US7799213Jul 8, 2005Sep 21, 2010Baker Hughes IncorporatedAdding wash water containing gluconic acid, C2-C4 alpha-hydroxy acids, poly-hydroxy carboxylic acids, thioglycolic acid, chloroacetic acid, polyhydroxy acids, polyglycolides, or glycolate ethers to hydrocarbon oil and resolving the emulsion with electrostatic coalescence; phosphate hydrolysis
US7867382 *Mar 19, 2010Jan 11, 2011Charlotte DroughtonRemoving contaminants and breaking emulsions in a feedstream of a crude oil source containing contaminants, metal salts, and water by contacting with a zeolite and demulsifier to separate to produce purified hydrocarbons; contacting with an asphaltene precipitant
US8372270Jan 18, 2011Feb 12, 2013Baker Hughes IncorporatedAdditives to enhance metal removal in refinery desalting processes
US8372271Feb 23, 2009Feb 12, 2013Baker Hughes IncorporatedAdditives to enhance metal and amine removal in refinery desalting processes
US8425765Sep 9, 2011Apr 23, 2013Baker Hughes IncorporatedMethod of injecting solid organic acids into crude oil
Classifications
U.S. Classification208/230, 208/48.00R, 208/241, 208/253, 208/251.00R
International ClassificationC10G21/08
Cooperative ClassificationC10G9/14, C10G21/08
European ClassificationC10G9/14, C10G21/08