HU181507B - Process for the elimination of acid traces from liquid hydrocarbons - Google Patents

Abstract

For removing acids from liquid hydrocarbons, these are treated with an aqueous base. The mixture of liquid hydrocarbons with the aqueous alkali is introduced into a bed which contains a hydrophilic medium, so that the aqueous phase droplets present in the hydrocarbon phase coalesce to form larger drops and thus settle out of the hydrocarbon phase. The coalescence medium used is preferably activated carbon or anthracite, bituminous coal or lignite. Due to the intimate contact between the aqueous base and the liquid hydrocarbon in the bed of the medium, not only high utilisation of the base is achieved, but a high concentration of salts of the acids removed from the hydrocarbon, for example naphthenic acids, is also obtained in the aqueous phase, so that the acids in question can be recovered as a by-product of the process.

Description

The present invention relates to a process for removing acid traces from liquid hydrocarbons by coagulation.

Many hydrocarbons are known to contain sulfur in the form of thiols (mercaptans). Thiols are almost always present in liquefied hydrocarbon gases, cracked naphtha 5, gasoline obtained by direct distillation of petroleum, and heavier hydrocarbon distillates such as kerosene and fuel oil.

The presence of thiols in hydrocarbons is disadvantageous mainly because of their strong odor, but also in some cases because of unwanted reactions with other hydrocarbons and can corrode equipment.

Many have attempted to develop methods for the removal or conversion of thiols. According to the very first methods, the hydrocarbons were treated with alkali, clays and hydrogen. Significant progress was made in the treatment of hydrocarbon distillates by the UOP Merox process in 1959.

The October 26, 1959 issue of the Oil and Gas Journal describes the Merox process and some earlier methods for removing mercaptans. 20

In the Merox process, mercaptans are oxidized to disulfides in the presence of oxygen or alkali using a catalyst dissolved in or applied to a support.

U.S. Pat. No. 3,108,081 discloses a mercaptan oxidizing catalyst containing an metal phthalocyanide salt on an adsorbent. Sulfonated metal phthalocyanides, including the monosulfonate, are particularly preferred as an example of the process.

In the industrial process, a variety of catalyst poisons or other harmful substances may be present in the 30 feed hydrocarbon feedstocks for thiol removal or conversion. Of these, trace amounts of naphthenic acid and hydrogen sulfide can often be expected.

Sulfur hydrogen is already present initially, but may be a by-product of a preventive operation if the sulfur compounds were decomposed to sulfur hydrogen at high temperatures in the presence of hydrogen. If the hydrocarbon processed was petrol or kerosene, most of the hydrogen sulphide is removed during distillation. However, removal is not always complete and requires further treatment of the hydrocarbon.

Naphthenic or other carboxylic acids are often found in petroleum. During distillation, naphthenic acids are distilled together with similar boiling hydrocarbons and concentrated in different fractions. Naphthenic acids are soluble in both hydrocarbons and aqueous media and are often classified as surfactants due to their activity at the interface between liquid hydrocarbons and water. Neutralized with alkali salts, the naphthenic acids form alkaline naphthenates similar to soaps. As such, they tend to form emulsions from the hydrocarbon phase and the aqueous phase and make it difficult to separate the oily phase and the aqueous phase. Because of their properties, naphthenic acids should also be removed from the finished product if the presence of an aqueous emulsion is detrimental to them, and from the raw materials to be treated with the chemical, if proper treatment is disturbed. ...

Accordingly, a variety of methods for resolving difficulties have been developed in treatment procedures. One method is simply to fill a large portion of the treatment vessel, known as a pre-washer, with dilute aqueous alkaline solution and to pass the hydrocarbon to be treated. The hydrocarbon feedstock is usually introduced through nozzles to provide intimate contact between the hydrocarbon and the dilute alkaline solution. Sometimes, for better contact, the alkaline solution is circulated by a pump, thereby allowing mixing with the hydrocarbon entering the tube. The concentration and amount of the alkaline solution are usually adjusted to absorb very little of the weakly acidic thiols present in the raw material. Alkaline pretreatment removes only the more acidic naphthenic acids, hydrogen sulphide and other trace amounts of acidic compounds. If the product is allowed to contain only very low acidity, the prewash may be followed by a coagulating sand filter, which removes any aqueous droplets of saline from the treated hydrocarbon feedstock. However, the sand filter requires constant handling to maintain its coagulability and the aqueous alkaline solution attacks the sand.

Unfortunately, such treatment does not always solve the acid removal problem in a satisfactory manner. The use of a large pretreatment tank increases the investment cost of the plant and is not always suitable for the proper use of the alkali. Best for removal of naphthenic acids! efficiency can be achieved with a very dilute alkaline solution. For a batch pre-wash system, this results in cyclical changes in the efficiency of naphthenic acid removal. The highest efficiency is achieved when the alkaline solution is fresh and the least effective before disposal of the alkaline solution. Due to the batch nature of the process and the surfactant nature of the naphthenate soaps, a certain amount of the unused alkaline solution is always destroyed by the spent alkaline solution.

Even if a conventional coagulant, such as a sand filter or a mesh cloth, is added after the prewash, it is sometimes the case that the treated hydrocarbon contains more than the permitted salts. The reason for this is that the efficiency of the coagulating apparatus depends on several factors. Proper efficiency can only be achieved within a narrow speed range and loss of efficiency is a common phenomenon during use, as particle deposition, sand abrasion, sand passage formation, and other factors reduce performance. Because conventional coagulants could not achieve sufficient efficiency without frequent maintenance, electric coagulants were used. These devices are similar to desalters well known in the treatment of petroleum, by which the salt water content of the oil is removed. Electric coagulants allow sufficient removal of the naphthenic acid salts from the prewashed hydrocarbons to meet the quality requirements of the material to be further processed or any standard requirements, such as the water separation of jet fuel. However, electric coagulants are expensive. Their management is cumbersome, and this is partly due to the rise in wages and partly in energy costs.

Another difficulty with previous pre-wash processes is the storage of large quantities of used chemicals. As mentioned above, the efficient operation of batch-type prewash tanks precludes the complete use of an alkaline solution. In a relatively large amount of the solution in the prewash tank, there is always a significant amount of neutralized alkali. In this way, if a relatively large amount of non-neutralized alkali is discarded at the same time, the acid removal efficiency of the alkali solution is no longer adequate. This is a problem not only because of poor reagent utilization but also because of the difficulty in destroying the free base.

Another disadvantage of batch prewash is that naphthenic acids present in the alkaline phase used are not easily recovered. If recovery is attempted, the alkaline solution used must first be acidified and then the acid separated from the oil. Since the mercaptan converting processes use dilute solutions in the prewash operation, the recovery of naphthenic acids is generally not considered worthwhile. In this way, potentially valuable raw materials are lost. Naphthenic acids can be used as a drying component in paints, wood preservatives and, to a certain extent, high pressure (EP) lubricants. Naphthenic acids are used as solvents for rubbers, various resins and polymers, aniline dyes, petroleum clarifying agents, insecticides and as an additive to wood oil to promote crack-free drying.

Because of the above, oil refiners are searching for a process that allows good separation of the acid, is economically feasible, and provides a nearly stoichiometric utilization of the alkaline solution. It is also necessary that this process is continuous and that large amounts of alkaline solution need not be drained and moved frequently.

The present invention relates to a process for removing the acid content of a liquid hydrocarbon, which comprises mixing an aqueous alkali solution with the hydrocarbons; passing the resulting mixture onto a coagulating bed of hydrophilic material; separating the hydrocarbon phase and the separate aqueous phase on this bed; and recovering on the bed a hydrocarbon phase having a lower acidity than the initial product and an aqueous phase nearly saturated with the acid content.

More particularly, the present invention relates to a continuous process for the removal of naphthenic acids from kerosene distillates such that 100 to 120% by weight of the distillate and the theoretically 1 to 3% aqueous sodium hydroxide solution required to neutralize the distilled naphthenic acids are present. ; the resulting mixture was passed through a further 0.5 to 20 hours ^-1 coalescing bed of a liquid space velocity of a hydrophilic material and the aqueous alkali is used for selecting as coagulation of the bed in this kerozinpárlatból; the resulting kerosene, containing 0 to 10% of its original naphthenic acid content, is drained from the lower part of the bed as the product of the process and the aqueous phase is discharged at the bottom of the carbon bed.

The process of the present invention can handle any hydrocarbon distillate containing an amount of acid. For example, naphthenic acids are generally found in distillates having an end point above 150 ° C in accordance with ASTM D 86. Most intermediate distillates contain hydrogen sulphide in oil refineries. Catalytic cracking products often contain carboxylic acids. For all these materials, the process of the present invention can be applied with excellent results.

Most of the kerosene distillates that are treated to convert thiols have a high content of naphthenic acid. Naphthenic acid content is usually characterized by the number of acids, its usual unit being the number of mg of KOH required to neutralize one gram of sample. The product specification most often specifies the maximum permissible acid content of jet fuel in 0.010 mg KOH / g. Today, raw materials with an acid number greater than 0.100 mg KOH / g are counted. The present intermittent prewashing units liquor oxidation ctnnált szaém- asphaltic ¹ Arai I, together with their associated has the koaguláltatóval. fire omen the ure, <auénen, idapté: it is idle time to burn today.

: to how do you iala: zetIzist y - one s mento nat100 ;; the deacon, he understood the pott '<, i sansa conquerors. | iforyakalálíató. even with naphthenic one · 1OH ί door-openers, they cannot bring the naphthenic acid content below 0.025 mg KOH / g. Failure to apply pre-removal and feed such a high naphthenic acid feed into the thiol converting unit would cause malfunction of the converter and result in product loss. The acid number of a kerosene or other hydrocarbon distillate is by any of several known methods, such as ASTM-D-3242, ASTM-D-3339, ASTM-D-74, ASTM-D-664, and so on. can also be determined according to a standard specification.

The aqueous base to be used may be any inorganic base soluble in any aqueous (or 10 alcoholic) solvent. Both sodium hydroxide and potassium hydroxide are suitable, but sodium hydroxide is preferred because it is cheaper. A relatively dilute aqueous alkaline solution is required to dissolve the naphthenic acids in the aqueous phase. The solubility of the alkali naphthenates in the aqueous phase decreases proportionally with the increase in the alkaline content of the aqueous phase. The solubility of the salts of other acids also influences the concentration of the alkaline solution which is useful at room temperature.

Regardless of the type or concentration of alkali used, only a small excess of alkali can be employed according to the invention, depending on the varying acidity of the raw material.

The raw material and the aqueous alkaline phase are contacted in a simple mixer before being introduced to the coagulant bed.

The coagulation bed is formed from a hydrophilic material that is not attacked by the alkali, such as anthracite or activated carbon. Suitable activated carbon can be prepared, for example, from sawdust, lignite, bituminous coal, peat, oil black. Particularly preferred is ground and graded anthracite.

Contact between the hydrocarbon, the alkaline solution and the coagulation bed can be achieved by any suitable means. The coagulant can be applied to a resting or moving bed. The process may be carried out batchwise. The material to be treated may also be introduced into the coagulation bed 35 from the bottom up, top down or radially.

The amount of coagulant available is determined by the properties of the raw material and the desired product quality. It may be necessary to adjust the parallel coagulation beds 40 so that one can be regenerated while one is in use. For maximum acid removal, we can also work in series-connected equipment. A multi-bed coagulating, parallel-running unit can also be provided. 45

The amount of coagulant required may be determined as a function of the fluid flow rate. Generally, a large amount of coagulant is required to maintain a fluid space velocity of 0.5 to 20 hours. Similarly, the shape of the dormant catalyst bed should be chosen such that the fluid 50 passes through the bed at the space speed at which efficiency and cost are minimized.

The best results are obtained when the average particle size is in the range of 0.1 to 6.0 mm, with particles having a particle size of 0.6 to 2.0 mm being particularly preferred.

The temperature and pressure at which the aqueous alkali solution is contacted with the raw material and the mixture is not critical to the coagulation bed. The ambient temperature is usually satisfactory if it is above the freezing point of the aqueous phase and above the freezing point of the oily phase. The temperature of hydrocarbon products in petroleum refiners is generally from 10 to 60 ° C, and the present invention is well suited to this temperature range. The lower limit of temperature is usually determined by the temperature at which the viscosity of the liquid is already 65 such that good contact between the aqueous phase and the fresh feedstock is not possible and the separation of the aqueous / oily phase would be difficult. In the range of 25-60 ° C, good results are generally obtained. Conventional raw materials flow easily at these temperatures, and contact and separation of the aqueous and hydrocarbon phases is easier. The treatment can be performed at much higher temperatures; this may be necessary when handling heavy, highly viscous materials. Higher temperatures facilitate contact and increase reaction rates, but usually without the use of high temperatures, the same acid removal can be achieved. The acid deprotection process of the present invention requires maintaining the pressure necessary to form the liquid phase, since both contact and separation of the aqueous and organic phases are completely in the liquid phase.

Injection of the alkali has a dual role. Not only does the alkali neutralize the acid content of the raw material, it also moisturizes the surface of the coagulant. Thus, the process of the present invention is also very effective because the acids react with the alkali not only in the mixer in front of the coagulation bed but also on the coagulation bed. The intense, intimate contact between the alkali and the acid allows the process of the present invention to be effective.

Once the acid-alkali reaction has taken place, there is still a dispersed phase in the hydrocarbon that needs to be removed. This is another function of the coagulation bed. On the bed, the dispersed aqueous phase gradually coagulates into larger droplets, eventually forming large droplets which separate and collect at the bottom of the coagulant, from where they can be separated. The accumulated aqueous phase is best discharged automatically from the coagulum using a level regulator. The advantage of the automatic level control is that it really makes the process continuous and requires little or no human supervision.

The bottom of the coal bed is preferably supported by a grate which retains the carbon but allows the aqueous alkaline solution used to pass to the drain. Particularly preferred are the well known Johnson grilles available from UOP Inc. Johnson Division. These gratings are formed from wedge bars welded to a support frame. They are very strong, usually do not clog, and have a relatively large open surface to allow fluid to flow. The hydrocarbons can be fed to the carbon bed on the carbon bed of the same design and then drained from there.

The drawing is a simple schematic flow diagram of an embodiment of the method of the invention. The dilute alkaline solution is continuously mixed with the acidic feedstock and the resulting mixture is passed through a coagulating bed.

In the first step of the process of the present invention, the acidic feedstock flowing in line 10 is contacted with a dilute aqueous solution of liquor from the storage tank (not shown) via line 21 and through line 22. The alkali is fed into the mixer 2. The mixture of raw material and alkali is fed through line 11 to the coagulation column 3. The coagulation column 3 consists of the coagulation bed 4, the inner distributor 8, the manifold 5 and the drain grate 6.

The substantially acid-free treated hydrocarbon is drained from the carbon bed through the pipe 5 and the product line 12 and then stored in further processing units or stored (not shown).

The aqueous phase coagulating on the carbon bed drains through the bed of coagulated pond 3181507 and passes through the grate 6 to the drain pan 7. Continuous drainage of the used aqueous phase through 23 conduits is achieved by means of a level regulator.

Example 1

We tested the procedure in a laboratory-scale experimental apparatus. The raw material was particularly high kerosene with an acid number of 0.084 mg KOH / g. The coagulation bed consisted of 50 ml of activated carbon from Mórit Co. The carbon had a stated particle size range of 0.55 to 1.68 mm and 90% of the particle diameter was in the range of 0.6 to 2.0 mm. The carbon was placed in a small pressure vessel in a resting bed. The inside diameter of the tank was 25 mm and the height of the bed was 100 mm. The carbon was held at the bottom of the tank by a glass wool plug. The alkaline solution used to neutralize the naphthenic acids was a dilute aqueous solution of sodium hydroxide,

With 1.5% sodium hydroxide. The alkali was added by slow injection with a needle. The addition of the alkali was due to the small size of the apparatus and the very efficient use of alkali by the process according to the invention. Before being transported to the coagulation bed, the kerosene was mixed with the sodium hydroxide solution using an ultrasonic mixer.

The acid number of the raw material was measured. The activated carbon hydrocarbon product was tested for both sodium content and acid number. The raw material was re-analyzed after mixing with the alkali but prior to coagulation to check the calculated amount of sodium hydroxide. The alkaline content was also determined by acid titration and atomic absorption spectrometry.

Experiments were performed at both 2.0 and 4.0 hrs of fluid space velocity, i.e., 100 and 200 mL / h of feedstock.

The experimental results are shown in Table I below.

Table I

Time. hour Space speed hour ^-1 I would The mole of the raw material is NaOH / mole acid acid number mg KOH / g Naturally occurring ppm added by titration by atomic absorption spectrometry 0-8 2 0,001 0.25 8-17 2 0,010 1.11 0.46 17-38 2 0.011 38-73 4 0.029 L5 1.77 1.29 0.27 73-80 4 0,009 0.34 1.26 0.60 0.10 80-100 4 0,004 0.45 1.28 1.29 0.10 100-124 4 0.023 2.2 1.14 0.60 0.34 124-152 4 0,005 3.6 1.14 0.58 0.77 152-179 4 0,018 8.1 1.14 0.40 0.74 179-107 4 0,036 19 1.14 0.48 1.03 197-221 4 0,006 3.6 1.14 0.34 0.53 221-248 4 0,004 7.1 - - 0.80 248-273 '/ Z 4 0,003 6.1 0.74

Example 2

Another experiment according to the invention was carried out in a plant-size apparatus. The raw material was kerosene from Lousiana and Illinois. An existing device was used as a coagulating bed in the oil refinery. We have not tried to design suitable equipment before, but rather try to use our existing equipment on a larger scale.

We were unable to obtain a suitable mixer for thorough contact between the kerosene raw material and the alkaline medium; alternatively, mixing was performed using a valve in front of the coagulant.

The alkaline solution used was the sodium hydroxide solution of 4-6 ° B available at the plant. According to our calculations, to neutralize kerosene from Louisiana crude oil, 11.4 liters per hour would be required, and to neutralize the acid content of kerosene from Illinois basin 5.7 liters per hour. The coagulating medium was 0.55-2.38 mm Calgon SGL activated carbon. In the Louisiana raw material, the alkali initially

It was added at a rate of 37.8 liters per hour or more, taking into account the acidity, which is mainly composed of naphthenic acids. This amount of alkali initially reduced the acid number of 0.10 mg KOH / g of kerosene to 0.0096 mg KOH / g. The residual drained alkaline solution is only approx. 50% responded. The alkali feed volume flow rate is hereafter

It was reduced to 28.8 liters / hour, but at this dosage acid removal was inadequate. The analyzed kerosene had an unacceptably high acid number of 0.032 mg KOH / 100 ml. However, the reliability of the analysis is questionable because sampling was difficult. 60% of the lowered alkaline solution reacted. The alkaline solution emulsified in kerosene contained 0.042-0.067 ppm NaOH. We were expecting less use of alkali because, in our experience, it is easier to separate alkali from hydrocarbons in an industrial scale than in a pilot plant.

II. spreadsheet

Time, clock Speed Square. hour ' ¹ The acid number of the product is mg KOH / g Well (PPm) · NaOH added by titration ppm 0-12 4 0,005 73 18 12-23 4 0,017 73 16 23-37 4 0,010 1.2 73 22 37-45 4 0,007 1.4 (temporary term turbidity in wedge) 45-53 4 0,005 73 32 53-64 4 0,016 (appearance of gel in the separator) 64-73 4 0,009 75 20 73-80 4 0,006 75 19 80-89 4 0,005 - - 89-99 4 0,005 75 45 99-108 4 0,003 75 64 108-118 4 0,005 75 11 118-126 4 0,008 - - 126-137 4 0.023 73 15 137-150 4 0,010 2.8 73 13 150-159 4 0,007 73 19 159-166 4 0,005 71 68 166-189 4 0,006 71 11 189-196 10 0,012 2.5 69 89 196-204 10 0.011 12.9 68 39

* The stoichiometric NaOH requirement was 62 ppm.

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Example 3

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Further experiments were performed in the experimental apparatus described in Example 1. In these experiments, activated carbon from the Darco Company was used, having a nominal particle size of 0.55-1.1; and 90% of the particles had a diameter in the range of 0.6 to 2.0 mm. The crude material was identical to that described in Example 1. In the experiments of Example 3, 1.2 times the amount of alkali theoretically needed to neutralize the naphthenic acids was fed. Our alkaline solution was slightly more concentrated than the sodium hydroxide solution 5'Be (3.2%) used in the first set of experiments. The temperature in the reactor

172.4 'C, pressure 0.56 bar. The results are shown in Table II. Table 1.

After 1 hour of operation, a gel-like substance appeared in the separator and was continuously formed during the experiment. At the 99th hour of the experiment, intermittent blockage occurred. Occasionally, a temporary clouding of the product was observed, but this usually resolved after a few hours. However, by the end of the experiment, the time to clear up had already increased to 7 days. In our opinion, the higher concentration of sodium hydroxide caused the formation of a gel-like substance, so that the alkaline concentration should be accurately adjusted.

Example 4

The same apparatus and raw material were used as in Examples 1 and 3. Anthracite carbon is now used as a coagulant. The carbon had a nominal grain size of 0.84 to 2.0 mm and a mesh size of 1.68 to 0.84 mm. In this example, a slightly thinner alkaline solution, namely sodium hydroxide solution at 3 ° B (1.8%), was used. The experiment was continued at a fluid space velocity of 4.0 hours until the raw material was consumed. The experimental results are shown in Table III. are summarized in Table.

This experiment generally yielded better results in the removal of naphthenic acid, according to the measured acid number. It is also a very favorable result in this experiment that the sodium content of the product is significantly lower than in the previous cases, although the sodium content of the product is acceptable in the procedures of Examples 1 and 3 as well.

In the procedure of Example 4, the better result is primarily due to the lower concentration of sodium hydroxide, but it is also believed that anthracite as a coagulating grain has a particularly beneficial effect.

III. spreadsheet

Drink. hour Space speed, hour ¹ The acid number of the product, mg KOH / g Na (ppm) NaOH added by titration ppm 0-11 4 0.046 - 68 - 11-23 4 0,014 3.9 68 12 23-35 4 0,008 - - 8 35-48 4 0,007 1.9 67 31 48-70 4 0,005 0.63 67 60 70-89 4 0,006 0.50 67 23 89-97 4 0,005 - 67 28 97-120 4 0,004 0.92 67 31 120-144 4 0,006 0.66 67 40 144-168 4 0,006 1.05 67 36 168-175 4 0,006 - 67 35

In the process of the present invention, the coagulation bed, when used to remove naphthenic acids, may be saturated with naphthenic acid salts. A variety of regeneration processes can be used to reactivate the bed and recover naphthenic acid salts that can be used as valuable by-products.

It is believed that the regeneration can be done properly simply by bypassing the bed and passing hot steam through it. For a more complete regeneration of the bed and recovery of naphthenic acid, primarily in the form of its 10 salts, it is possible to acidify the salts. To this end, the coagulation bed is eliminated from the previous flow of hydrocarbon and aqueous solution, and an acidic aqueous solution is circulated through the bed to desorb the naphthenic acids from the activated carbon. By using sufficient acidic-aqueous solution, the bulk of the naphthenic acids can be removed during acidification. Desorption of naphthenic acids is facilitated when hot steam is passed through the reactor. Naphthenic acids are volatile in vapor and the process results in almost complete regeneration of the coagulation bed. If the carbon bed does not regenerate well due to these mild treatments, it may be necessary to treat it with higher temperature steam; or with hydrocarbon solvents such as benzene, acetone and methanol to facilitate removal of naphthenic acids and acid salts from the coagulant bed.

An interesting feature of the process of the present invention is that, while excellent results are obtained in removing the acid content of the raw material or kerosene prepared for the conversion of thiols, the concentration of naphthenic acids often increases up to 1000 times and allows the recovery or simplification of naphthenic acids. The bulk of the naphthenic acids, when equilibrium is formed on the coagulation bed, appear in the aqueous phase.

The present invention is also applicable to the removal of the hydrogen sulfide content of hydrocarbons. Thus, the hydrocarbon containing 0.01% by weight of sulfur-hydro35 gene is treated with 6% by weight of aqueous sodium hydroxide solution and passed through a coagulation bed in a direct current. Preferably, the coagulation bed is formed from carbon commercially available under the trade name Calgon with a nominal particle size of 0.6 to 2.0 mm. Using a 30% lye excess, less than 0.0005% sulfur hydrogen can be detected in the product leaving the coagulation bed.

The efficiency of the removal of some acids is limited by equilibrium conditions. Partial removal of weak acids such as thiols and phenols can be accomplished by adjusting the equilibrium conditions to the alkali concentration and also depends on the nature of the components to be removed.

It is preferable to use a more concentrated alkali for the removal of hydrogen sulfide than for naphthenic acids because the salts of hydrogen sulfide are more soluble than the salts of naphthenic acid; Good results can be obtained with 2-10% sodium hydroxide solution.

According to measured data, the present invention is very effective in reducing the acidity of kerosene heavily contaminated with naphthenic acid in the removal of naphthenic acids. The naphthenic acid content can generally be reduced to 55 levels to allow the material to be further processed or commercially available.

It can be seen that the present invention achieves an almost stoichiometric utilization of the alkali. Acid neutralization is also more effective than prior art, since the effective surface area of the alkaline medium 60 is larger not only in the mixing and in the tubes but also in the coagulating bed. Higher operational flexibility and efficiency allows for handling at much lower hydrocarbon flow rates. The water uptake of the hydrocarbon is negligible 65 because the coagulation bed separates the water droplets separately

It can collect it in 181508 phases, and gravity separates this phase from the hydrocarbon. The cost of pretreatment is also lower with our procedure.

Claims (3)

Patent claims 1. A process for removing acids using an aqueous alkali solution in liquid hydrocarbons, characterized in that the liquid hydrocarbon into the aqueous alkaline solution, the resulting mixture is from 0.5 to 20 hours ^- the bed is passed into a coagulation 'resistant, hydrophilic material with a liquid space velocity of particulate anthracite or activated carbon, separating the hydrocarbon phase and the aqueous phase on the bed and separating the reduced acid hydrocarbon phase. 2. The process of claim 1, wherein the mixture is fed to an anthracite coagulating bed. 3. The process of claim 1, wherein the anthracite or activated carbon has a particle size of 0.1 to 6.0 mm. 4. The process of claim 3, wherein the carbon is 0.6 to 2.0 mm.