CA1102268A - Trace acid removal - Google Patents

Abstract

TRACE ACID REMOVAL

ABSTRACT OF THE DISCLOSURE

An improved process is disclosed for removing trace acidic compounds from liquid hydrocarbons. Traces of acidic compounds, including carboxylic acids, H2S, naphthenic acids, et al, are present in most hydrocarbon streams. The presence of these acidic compounds is considered deleterious to accepted product specifications. The trace acidic compounds which in-terfere are removed via injection of a dilute aqueous alkaline solution into the hydrocarbon stream and passage of this stream through a coalescing bed.

Description

TRACE ACID REMOVAL
.... _ SPECIFICATION
Many hydrocarbons contain sulfur in the form o~ mer-captans (thiols). Mercaptans are almost invarlably present in LPG, cracked gasolines, straight run qasolines, natural gasolines, and in heavier hydrocarbon distillates incLuding e.g., kerosene and fuel oil.
These mercaptan components are objectionable mainly because of their strong odor, but also, in some cases, due to their objectionable chemical reaction with other hydrocarbons or fuel system components.
There have been many attempt~ to provide processes which would remove or convert mercaptans. Some of the earli-est processes included treatment o~ the hydrocarbon fraction with caustic, clays, and hydrotreating. A significatn improve-ment in the treating of hydrocarbon ~ractions was made when ~ lS A thé UOP Merox~Process was announced to the industry in 1959.

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- 2 -., . , . , ~ , ., .. . , . . . ~ , ~he Oil and Gas Journal, in the October 26, 1959 edition, ; contains a discussion of the Merox~Process, and also of some prior art processes.
This process used a cakalyst which was soluble in caustic, or alternatively held on a support, to oxidiz~
- mercaptans to disu~fides in the presence of oxygen and caustic.
In U.S. Patent 3,108,081, there is disclosed a catalyst comprising an adsorptive carrier and a phthalocyanine catalyst for the oxidation of mercaptans. This patent taught that a particularly preferred phthalocyanine was the sulfonated derivative, with the monosulfonate being especially preferredO
In commercial operation, a number of catalyst poisons or other deleterious materials are present in the hydrocarbon feed to the processing units provided for mercapta~ removal or conversion. Trace amounts of acidic components such as naphthenic acids and H2S are frequently encountered.
H 25 iS oEten naturally occurring but also present as a by-product of some earlier steps in processing wherein sulfur compounds, in the presence of hydrogen and high ~0 temperature, decompose to form H 2S . When the hydrocarbon feed stream being txeated is either a naphtha or a kerosene, most of the H2S iS removed by distillation; however, such removal is not always complete and ~urther treatment of the hydrocarbon stream is required.
Naphthenic acids, and other carboxylic acids, are ;~
c~mmonly found in crude oil. During distillation naphthenic acids ~: .
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are co-distilled with the hydrocarbon of similar boiling ranges concentrating in the various distillate stream~.
Naphthenic acids possess characteri~tics which permit solu-bility in both hydrocarbon and aqueous medium and are often referred to as surfactants because of their activity at sur-faces such as the interface between a liquid hydrocarbon and water. When neutralized by alkaline salts, naphthenic acids form alkali naphthenates which are chemically similar to soaps.
As such, they tend to emulsify hydrocarbon and aqueous phases interfering with efficient separation of oil and water phases.
Because of these properties, they must be removed from finished products where aqueous emulsions are intolerable or from the feed to chemical treating processe~ where they interfere with efficient processing.
Accordingly, the treating arts have developed a number of ways of handling the~e problems. One way is to simply pro-vide a large vessel, termed a pre-wash, partially filled with dilute aqueous caustic, di~per e the hydrocarbon containing trace acidic components into the aqueous caustic, and pass the hydrocarbon qtream up through the ves~el. Typically the enter-ing hydrocarbon stream will entsr the pre-wash vessel through a series of nozzles to insure that there is intimate contact of hydrocarbon with dilute caustic. Sometimes contact is ob-tained by circulating the caustic inventory with a pump to mix the caustic with entering hydrocarbon in the piping. The strength and quantity of the caustic solution u~ed are gene-rally adjusted so that very little of the weakly acidic mercap-, 6E~

tans in the feed are absorbed by the caustic. Only the moreacidic naphthenic acids, H2S and other trace acidlc compounds are removed by the caustic pretreatment. When very low acid contents in the product are required, the pre-wash vessel may S be followed by a sand filter coalescer which will remove en-trained droplets of aqueous salts from the hydrocarbon stream being treated. However, a sand filter requires frequent atten-tion to maintain its coalescing efficiency and sand is subject to attack by aqueous basic solutions.
Unfortunately, such an operation does not always pro-vide a satisfactory solution to the problem of removing acids.
Use of a large pre-wash vessel adds to the capital expense of the plant and may not provide efficient utilization of the caustic solution. In the case of naphthenic acid removal, very lS dilute caustic must be employed for most efficient acid removal.
Use o~ a batch pre-wash system also means that the efficiency of naphthenic acid removal is cyclical. The efficiency is greatast when the caustic is fresh, and lowest just before the weak caustic is di~carded. Because of the batch natuxe of the process, and because of the surfactant nature of naphthenate soaps, a certain amount of unneutralized caustic is always discarded with the spent caustic.
Even with use of a conventional coalescer following the pre-wash vessel, e.g., sand filter or mesh blanket coales~
cer, the entrainment of acidic salts i~ still sometime~ exces-sive. This is because the efficiency o~ coalescers is depend-ent on many factors. Reasonable efficiency can only be obtained within a relatively narrow velocity range and deterioxation in efficiency with use is common as particulate buildup, sand attrition, channeling, and other factors cause deterioration in performance. The inability of the conventional coalescers to maintain high efficie~cies without frequen~ maintenance has lead to the use of electrical coalescers. These devices are similar to the well known desalter~ used on crude petroleum to remove entrained water containing dissolved salts. With the use of an electrical coalescer, it i8 pOS ible to remove enough of the entrained caustic containing the naphthenic acid salts from a pre-washed hydrocarbon to satisEy the requirements of downstream processing units and, where applicable, such ~ ~pecifications as water separation Prom jet fuel for example.
; Unfortunately, the electric coale~cers are proprietary items and add greatly to the expen~e of pretreatment equipment.
They also require careful attention increa3inq the utilitie~
cost and operator expense.
Another problem experienced by the prior art pre wash processes is d1spo~al of large quantities of spent reagent.
As previously men~ioned, efficient operation of the batch type pre-wash vessel precludes total exhaustion of the alkali solu-tlon. There i5 alway~ a significant amount of unneutrali~ed caustic remaining in the relatively large liquid reserve of alkali solution in the pre-wash vessel. Thus, when the effi-clency of acid removal by the alkaline solution i~ no longersatisfactory,a high peraentage of unn~utralized alkali i5 unavoidably discarded. This is a pro~lem, not only because : ; :: , . . . .

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of inefficient use of reagents, but because the free alkali repxesents a disposal problem.
Another disadvantage of a batch pre-wash i~ that the naphthenic acids present in the spent cau~tic phase are dif-ficult to recover. If an attempt is made to recover theseacids it is first necessary to reacidify the spent caustic and then separate acids from admixed oil. ~ecause of the dilute na~ure of the 3treams used in a pre-wash upstream of a mercaptan conversion process, the recovery of naphthenic acids is u ually considered not worthwhile. Thu , a source of potentially valuable raw material i~ lost. Naphthenic acids can be used as paint drier~, wood preservatives/ a~d to some extent in extreme pres ure lubricants. The naphthe-nic acids have also been u~ed as solvents for vulcanized rubber, various resins and gums, for aniline dyes, as clari~y-ing agents for mineral oil, as insecticides, and as additives to wood oil to permit drylng without cracking.

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Accordingly, xefiners continue to search for a process which would provide for efficient acid removal, be economical to operate, and provide near stoichiometric utilization of the alkali solution. There is also a need for a process which would be continuous to avoid the necessity of frequent dr~in-ing and handling of large volumes of alkali solution.
Accordingly, the present invention provides a method of removing acids from liquid hydrocarbons comprising~ (a) mixing an aqueous base with the hydrocarbon; (b) charging the mixture from step (a) into a coalescing bed of a hydrophillic media; (c) ~eparating in said bed a hydrocarbon phase and a separate aqueous phase, and (d) recovering from said bed as a product of the process a hydrocarbon phase containing a re-duced acid content and an aqueouR phase almost saturated with acids.
In a more limited embodiment the present invention provides a continuous process for removing naphthenic acids from a kerosene stream compriRing: (a) continuously pass-ing kerosene and 100 to 120~ of the amount of 1 to 3 wt. %
aqueous sodium hydroxide solution required by stoichiometry to neutralize the naphthenic acids in said kerosene to a mixing means; (b) passing the mixturP from step ~a~ downflow through a fixed bed of hydrophillic coalescing media at a LHSV of 0.5 to 20, and coalescing in said bed a spent aqueous caustic phase from a kerosene; (c) withdrawing said kerosene .

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containing 0 to 10% of its original naphthenic acid content from a lower portion of said bed as a product of the process;
and, (d) withdrawing said aqueous phase from the bottom of the charcoal bed.
In another embodiment, the present invention provides a process for recovery of naphthenic acid~ ~rom liquid hydro-carbons which comprise~: (a) pa~ing liquid hydrocarbon~, and sufficient aqueou~ ba~e to neutralize the naphthenic acids, to a mixing means; (b) pas~ing the mixture from step ~a) to a coale~cing bed comprising a fixed bed of a hydrophillic media;
(c) absorbing on said media at least a portion of the neutral-ized naphthenic acids present in the liquid hydrocar~on; and (d~ removing from said bed an aqueouæ phase compri~ing spent basic medium and a hydrocarbon phase comprising hydrocarbons depleted in naphthenic acid content.
The hydrocarbon stream3 which may be treated in the proces~ of the present invention are those containing any trace amount of acid. For example, naphthenic acid~ are usually found in streams with ASTM D 86 end points in excess of 150C.
H2S can be found in most refinery intermediate product streams.
Carboxylic acids are often present in catalytically cracked stocks. The method of the present invention can be applied with great æuccess to all of these stock9~
Many kero~ene charge stock~ which must be treated for mercaptan conversion frequently contain high naphth~nic acid contents. Naphthenic acid content is generally indicated by acid number, with typical units being milligram~ of KOH required 26~3 to neutralize one gram of sample. The product ~pecification for most jet fuels sets the maxim~n acid number at 0.010 mg KOH/g. Charge stocks are being encountered today which have acid numbers in excess of 0.100 mg KOH/g. The existing batch S type pre~wash units followad by a coal~cer can not efficiently remove naphthenic acids in a range above about 0.025 mg KOH/g.
The presence of such large amounts of naphthenic acids in the feed to a mercaptan conversion unit, if not removed, would re-sult in operating difficulties with the treating unit and loss of product. The acid number of a kerosene or other hydrocar-bon can be determined by any of ~everal methods of test such as ASTM~ 3242, ASTM-D-3339, ASTM-D-974, ASTM-D-664, etc.
The aqueous ba~e suggested for use may be any inorganic base soluble in aqueous (or alcoholic) solvent. ~oth NaOH and KOH are suitable, with NaOH being preferred because of it5 availability and low cost. A relatively dilute aqueou~ base is required to effect solubility of the naphthenic acid in the aqueous phase. Solubility of the alkali naphthenates in the ~aqueous phasq decreases as the concentration of alkali in the aqueous phase increases. Solubilities of other acid salts also limit the concentration of base in the solution that may be practically used at normal temperatures.
Regardless of the type or concentration of the base used, the present invention pe~nits operation with only a s1ight excess of base to allow for variation in acid concen-tration of the feed stock.

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;8 The feed stream and the aqueou~ alkali phase are contacted in a simple mixing device before entering the coalescing bed.
The coalescing bed is selected from the group of substrates which are not attacked by alkali, ~uch ~g vari-ous activated charcoal~, coal, lignite, shale, slag, cal-cined coke, etc., preferably with hydrophillic properties.
Examples of suitable charcoal~ include those derived from ground wood pulp, lignite coal, anthraci~e coal, bituminous coal, peat, petroleum black, and similar charcoals. Es-pecially preferred is ground and graded anthracite coal.
The contact of hydrocarbon with injected alkali and the coalescing bed may occur in any suitable manner. The coalescing medium may be maintained a~ a fixed ar moving bed.
lS Batch con~acting may also be employed. The stream may pass over the coalescing medi~m in upflow, downflow or radial flow.
The amount of coalescing media provided must be ad-justed to conform to the properties of the feed and to the desired properties of the product. It may be desirable to provide parallel coalescin~ beds so that one bed can be used :while another is being regenerated. Sexies flow to promote maximum removal of acid~ can also be used. Use of multiple beds in eries ~low with a parallel train i9 also possible.
The ~mount of coalescing media required may be speci-fied as a function of liquid flow rate. In general, enough coalesaing media should be provided so that the liquid hourly ' .

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space velocity will be in the range of 0.5 to 20. Similarly, the geometry of the pre~erred fixed bed of catalyst is such that the super~icial liquid velocity through the bed is chosen to provide the highest efficiency and lowest cost.
For best result~, the media particl~ 8iZ~ distribu-tion should be in a range of 0.1 millimeters to 6.0 milli-meters with particle sizes in a range of 0.6 to 2.0 mm ex-hibiting excellent properties.
The co~dition~ of temperature and pre~sure at which aqueou~ base contacts th~ feed, and in which th~ mixture con-~acts the coalesciny media are not critical. In general am-bient temperatures which are above the freeze point of the aqueous phase or the pour point of the oll pha~e can be used.
The ~ypical sundown temperatures of refinery hydrocarbon pro-duct streams are 10 to 60C, and the pxesent invention works well within these temperature rangas. The lower limit on temperature i9 usually set by the temperature at which the viscosity of the fluid becomes 80 great that good contacting of aqueous pha~e and fresh feed i3 precludad, and subsequent separation o~ aquesus phase from organic phase i hindered.
The upper limit of temperature i~ usually set by the degree of dehydration that can be tolerated in the ~ystem and the allowable water content of the treated hydrocarbon stream.
Operation at temperatures o~' 25 to 60C gives satisfactory results with many feed ~tream5. The normal material~ are very fluid at these temperature~, and contact and separation of aqueous and hydrocarbon phases i~ facilitated. Operation . . . ~

at much higher temperatures is possible, and may be desirable in the case of very heavy or viscous oils which must be treated. Higher temperatures promote con~acting and rate of reaction but adequate acid removal, for example, can usually be obtained without the expense of heating the stream ~o high temperature. The pressure under which the acid removal process of the present invention operates should be sufficient to main tain liquid phase operation as both the contac~ and separation of organic and aqueous phases occur entirely in liquid phase.
Pressure is not believed to be a significant variable. Accord-ingly, the pressure will generally be the least amount of pres-sure required to get the fluids through the processing units.
The function of the caustic injection is twofold. Not only does the caustic neutralize the acid in the feed, it also wets the surface of the bed of coalescing madia. T~us, the process of the present invention works efficiently because acids and caustic react not only in the mixing devices upstream of the coalescing bed, but also in the coalescing bed. It is because of this extensive and efficient contact of caustic and acid that the present invention works so efficiently.
There is still an aqueous phase dispersed in the hydro-carbon stream after reaction of acid and alkali is complete;
this a~ueous phase must be removed. This is anokher function of the coalescing bed. ~he dispersed aqueous phase i3 gradually coalesced into larger droplets by the bed finally forming large drops which separate and gravitate to the bottom of the coales-cing vessel for removal. Preferably a level controller auto-6E~

matically drains ~hs aqueous phase from the coalescing vessel as it accumulates. The advantage of the automatic level con-trol is that it makes the process truly continuous requiring little or no operator attention.
The charcoal bed is preferably supported by a flat screen which will hold up ~he charcoal but allow the spent aqueous base to pass therethrough for removal from the bed.
Especially preferred are the well known Johnson~ crPens avail-able from the Johnson Division of UOP Inc~ The~e screens consist of wedge shape rods welded onto a support. They are very strong and generally non-clogging, and provide a rela-tively large open area for fluid flow. The hydrocarbon stream may be added to and removed from the charcoal bed via circular screens of the same type of construction.
BRIEF DESCRIPTION OF TH~ DRAWING
The drawing shows a simplified, schematic flow diagram of one embodiment of the present invention wherein a dilute alkali solution is continuously injected into an acid bearing feed and the mixture passed through a coalescing bed.
DETAILED DESCRIPTION
In the first step of the process of the prësen~ inven-tion, an acid bearing feed stream in line 10 i~ contacted with a dilute aqueous base from storage tankq (not shown~ charged by metering pump 1 taking suction via line 21 and discharging via line 22. Caustic i9 charged to mixing device 2. The mix-ture of feed and base is charged via llne 11 to the coalescing vessel 3. Coalescing vessel 3 consists of coalescing bed 4, .: ' " . :~

6~3 inlet distributor 8, collector pipe 5, and drain screen 6.
Treated hydrocarbon, substantially free of acids, is removed from the charsoal bed via collector pipe 5 and product line 12, then charged to other processing units or ~torage (not shown).
The aqueous phase coalesced by the charcoal bed trickles down through the coalescing bed exibing via drain screen 6, into drain pot 7. Sight glass and level control means (not shown) provide for the continuous withdrawal of spent aqueous phase via line 23.
EXAMPLE I
A miniature pilot plant was used to test this invention.
The feed was a kerosene with an ex~remely high acid number of 0.084 mg KOH/g. The coalescing bed consisted of 50 cc of charcoal made by the Norit Co. The charcoal was designated as 10/30 mesh, and 90% of it had a particle diameter between 0.6 and 2.0 mm. The charcoal was disposed as a fixed bed in a small pressure vessel. The internal diameter of the vessel was 25 mm and the height of the bed was 100 mm. The charcoal was supported at the bottom by a plug of glass wool. ~he alkali solution added to neutrali~e the naphthenic acids was a dilute aqueous solution of NaOH. The caustic strength was l.5 wt. %. The base was added by slowly closing a hypodermic syringe. Such a method of adding caustic was ~ecessary because the plant was small and because the present invention makes very efficient use of caus-tic. An ultrasonic mixer was used to mix the kerosene with the NaOM upstream of the coalescing bed.

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The feed was tested for acid number. The hydrocarbon product, after pas-qage through the bed of activated charcoal, wa~ analyzed for both ~odium content and acid number. The feed, after mixing with caustic, but before coale~cing, was measured to confirm the calculated addition of NaOH. Both acid titration and atomic absorption sp~ctroscopy analyses of the mixture were used to determine alkali content.
Tests were run at 2.0 and a 4.0 LHSV, i.e., a charge rate of 100 cc/hr and 200 cc/hr, respectively.
The experimental results are reported in the ~ollow~
ing Table 1.
- Table 1 Product: ~ole~ NaOH/~ole Acid in Feed:
Hours LHSV Acid No. Na(ppm) Added Tltration_ AAS
: 15 0~8 2 0.0010.25 8-17 2 0.010 1.11 0.46 17-38 2 0.011 38-73 4 0.029 1.5 1.77 1.29 0.27 73-80 4 0.0090.34 1.26 0.60 0.10 80 100 4 ~.0040.45 1.28 1.29 0.10 100-124 4 0.023 2.2 1.14 0.60 0. 3 124-152 4 0.005 3~6 1.14 0.58 0. 77 152-179 4 0.018 8.1 1.14 0.40 ~.74 17~-197 4 0.036 19 1.14 0.48 1.03 197-2~1 4 0.006 3.6 1.1~ 0.3~ 0.53 ; 221-248 4 0.00~ 7.1 - - 0.~0 248-2731/2 4 0.003 6.1 - - 0.74 , .
., , : ... , .. ,,., : ~
' .':' '. ''`'' ~: ,.' .'`' , ` ., ' , EXAMPLE II
Another test was made of thiS invention in a commer-cially sized unit. The charge stocks used were kerosenes derived from Louisiana and from Illinois. The unit used an existing refinery vessel as a coalescing bed. No attempt was made to design the vessel beforehand, rather an attempt was made to use the equipment existing at the plant to try out this invention on a slightly larger scale.
No mixing device- was readily available to permit inti-mate contacting of the kerosene feed with the alkaline medium.As a substitute, a val~e was pinched partially shut upstream of the coaleccer.
The alkaline medium used was caustic available in the refinery, which had a concentration of 4-6 Baume. This con-centration was higher than desired but was the only strengthobtainable for the experiment. Calculations indicated that approximately 11.4 libers per hour of caustic injection was neces~ary to neutralize the kerosene derived from the Louisiana crude, while 5.7 liters per hour caustic was required for neutralization of acids contained in the kerosene derived from the Illinois basin material. The coalescing medium u~ed was Calgon SGL charcoal, 8 x 30 mesh. Caustic injection, using the Louisiana crude, was b~gun at a rate of 37.8 liter~ per hour, or cons1derably in excess o~ that required hy stoichio-metry to neutralize acids, primarily naphthenic acids. Thiscaustic injection rate reduced the initial acid number of the kerosene from 0~10 my KOH/g to 0.0096 mg KOH/g. The resulting drained caustic was only about 50~ spent. Caustic injection was further decreased to about 28.8 liters per hour, but this resulted in inadequate acid removal. The kerosene product by analysis contained an unacceptably high naphthenic acid content, 0.032 mg KOH/100 ml. This analysis might be ques-tioned due to difficulty in obtaining a representative sample.
The drained caustic was 60% spent, however. The amount of caustic which remained entrained in the product kerosene ranged from 0.042 to 0.067 ppm NaOH. This lower caustic entrainment was expected, because from my experience it is easier to sepa-rate caustic from hydxocarbons in a commercially sized unit than in a pilot plant.
EXAMPLE III
Further tests were then run in the pilot plant facility described in Example I. TheR~ tests were run with charcoal obtained from the Darco Company which had a nominal size of 10-30 mesh (90~ of the particles had a diameter between 0.6 and 2~0 milliliters). The charge stock used was identical to that used in Example I. In Example III the target amount of caustic injected was 1.2 times that theoretically required to neutralize naphthenic acids. The caustic material used was slightly more concentrated than that used in the first experi-ment, namely 5 Baume NaOH (equivalent to 3.2 wt. ~ NaOH).
The reactor temperature was 78 F, the reactor pre~sure was 80 psig.
The test resultR are reported in Table 2.

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Table 2 Product *PPM NaOH Added HoursLHSV Acid No. Na(ppm) Addition Titrat n 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 Haziness in Product) 45-53 4 0.005 73 32 53-64 4 Q.016 (Jelly Appearing in 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 ~9-lOS 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 11 189-1~6 1~ 0.012 2.5 69 78 196-204 10 0.01112.9 68 39 A gel like substance appeared in the separator after 64 hour~ of~operation and continued to be produced ~or the remainder of the experiment. A temporary plug developed at 99 hours .into the experiment. From time to time ~ome temporary *NOTE: 62 ppm NaOH required by stoichiometry . ~

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haziness would appear in the product but this would usually go away after several hours. The hazy product at the end of ~he run, however, required a standing period of up to 7 days to clear. It is believed that the higher concentration of NaOH caused the production of the gel-like substance indicat-ing the need to adjust the caustic concentration carefully.
EXAMPLE IV

_ . _ The same test apparatus and charge stock was used as in Examples I and III. In this example the coalescing mater-ial used was ground anthracite coal. The nominal particlesize of the coal was 0.84 to 2.0 mm, also designated as 10 x 20 mesh.
A sligh~ly more dilute caustic wa~ used in this experi-ment, namely 3~ Baume NaOH (equivalent to 1.8 wt. ~ NaOH). The experiment was conducted at a 4.0 LHSV, and continued until sup~lies of feed stock were exhausted. The experimental re-sults are reported on Ta~le 3.

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Table 3 Product PPM NaOH
Hours LHSV Acid No. Na(ppm) Addition Tltxation 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 l.g 67 31 48-70 ~ 0.005 0.63 67 ~0 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 Thls experiment was generally more succes~ful in lowering the naphthenic acid content of the produck) as indi-cated by the acid nu~ber thereof~ This experiment was also very satisfactory in that the sodium content of the product was significantly lower than that indicated in earlier exam-ples, although the sodium content of the product of Examples I and III is satisfactory.
Most of the improvement in Example IV is due to the lowered NaOH concentrations but there is perhaps a synergistic effect due to the use of anthracike as coale9cing medium.
: The coalescing bed of the presçnt invention when used for removal of naphthenic acids may eventually become saturated with naphthenic acid salts. To permit reactivation of the bed, b O --,, : .. , ... :
.: ' ' ' ' ' -' ' ' . ' ' ,'' . ' " ' and also to permit recovery of the naphthenic acid salts for use as a valuable by-product, a number of regeneration pro~
cedures can be used.
It is believed that a reasonable regeneration can be performed by merely removing the bed from the flow stream and passing hot steam over the bed. To provide a more complete regeneration of the bed, and to permit recovery of the naph thenic acid salts in the form of the acid rather than the salt, it would be also possible to re-acidify the salts in situ.
This may be accomplished by isolating the coalescing bed from the hydrocarbon and aqueous streams, circulating an aqueous, acidic solution over the bed, and desorbing the naphthenic acids from the charcoal. If a suficient quantity of acidic water is used, much of the naphthenic acids will be displaced in the acidification step. rhe desorption of naphthenic acids may be promoted by pasqage of hot steam over the reactor. The naphthenic acids are volatile with steam and this procedure should provide for almost complete regeneration of the coales-cing bed. If the charcoal bed is not readily regenerable with these mild techniques it may be necessary to go to higher tem-perature steam treatment, or treatment with various well-known hydrocarbon solvents such as benzene; acetone and methanol mix-tures to assist in removal of naphthenic acids and acid salts from the coalescing bed.
One o~ the interesting features of this invention i8 that while doing an excellent job of removing acids in the kerosene product or for feed to a mercaptan conver~ion unit, - 21 ~

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it also produces as much as a 1000 fold increase in the con-centration of naphthenic acids, permitting the possible re-covery of naphthenic acids where they are a desired by-product, and simplifying the disposal of these compounds where there is no market for them. Most of the naphthenic acids will be re-covered in the aqueous phase once an equilibrium amount has accumulated on the coalescing bed.
The present invention may also be used to remove ~2S
from hydrocarbon stream3. A hydrocarbon stream containing, e.g., 0.01 wt. % H2S may be contacted with an aqueous 6 wt. ~
NaOH stream and passed downward concurrently through a coales-cing bed. The coalescing bed preferably comprises a charcoal having a nominal granulation range of ~ . 6 to 2.0 millimeters available under the trade name of Calgon. Utilizing 30 percent excess base, the hydrocarbon product from the coalescex should contain less than 0.0005 wt. % H2S.
The efficiency of removal of certain acids is limited by equilibrium considerations at the opPxating conditions de-sired. Partial removal of very weak acids, e.g,, mercaptans and phenols, is also possible subject to equilibrium considera-tions, adjustment of base concentration, and dependent on the specific acidic component being removed.
It is pref~rred to use more concentrated base for re-moval of H2S than for removal of naphthenic acids. This is because salts of H2S are more soluble than salts of naphthenic - acids. NaOH concentrations of 2 to 10 wt. % will give good results.

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As applied to removal of naphthenic acids, the data indicate that the process of the present invention i5 very effective in reducing the acid number of a kero~ene s~verely contaminated with naphthenic acid. In general, the naphthenic acid content could be reduced to acceptable levels for further processing or sale.
It can be seen that the method of the pre~ent inven-tion provides for nearly stoichiometric utilization of the caustic. There is also more effective acid neutralization because of the larger effective surface area of basic medium7 not only in the mixing means, and piping, but also in the coalescing bed. There is greater flexibility and efficiency permitting operation with hydrocarbon flow rates much less than normal. There i5 negligible entrainment of aqueous solu-tion with hydrocarbon because of the ability o the coalescingbed to coalesce aqueous droplets into a separate phase that will separate by gravity, from the hydrocarbon. There is also afforded a reduction in cost of pretreatment facilities.

Claims (18)

I CLAIM AS MY INVENTION:

1. A method of removing acids from liquid hydrocar-bons, comprising:
(a) mixing an aqueous base with the hydrocarbon;
(b) charging the mixture from step (a) into a coales-cing bed of a hydrophillic media;
(c) separating in said bed a hydrocarbon phase and a separate aqueous phase; and, (d) recovering from said bed as a product of the pro-cess a hydrocarbon phase containing a reduced acid content.

2. Process of Claim 1 wherein the hydrocarbon feed is a kerosene containing naphthenic acid.

3. Process of Claim 1 wherein the hydrocarbon feed is selected from the group of naphtha and kerosene and wherein the acid comprises H2S .

4. Process of Claim 1 wherein the aqueous base is continuously added in an amount sufficient to neutralize from 100 to 200% of the acids present in the system.

5. Process of Claim 1 wherein the coalescing medium is selected from the group of anthracite coal, and charcoal derived from ground wood pulp, lignite coal, anthracite coal, bituminous coal, peat and petroleum black.

6. Process of Claim 1 wherein the coalescing medium is anthracite coal.

7. Process of Claim 1 wherein the particle size of the coalescing medium is within the range of 0.1 to 6.0 mm.

8. Process of Claim 7 wherein the particle size is 0.6 to 2.0 mm.

9. Process of Claim 1 wherein the mixture from step (a) contacts the coalescing bed while flowing down through it at a LHSV based on liquid hydrocarbon flow rate of 0.5 to 20 volumes per volume coalescing media.

10. Process of Claim 1 wherein the aqueous base is selected from the group of aqueous solutions of NaOH and KOH.

11. Process of Claim 10 wherein the aqueous base con-tains 0.01 to 50 wt. % alkali.

12. Process of Claim 1 wherein the acid comprises naph-thenic acid, and the aqueous base is NaOH at a concentration of 1 to 3 wt. %.

13. Process of Claim 1 wherein the acid comprises H2S
and the aqueous base is NaOH at a concentration of 2 to 10 wt. %.

14. A continuous process for removing naphthenic acids from a kerosene stream comprising:
(a) continuously passing kerosene and 100 to 120% of the amount of 1 to 3 wt. % aqueous sodium hydroxide solution required by stoichiometry to neutralize the naphthenic acids in said kerosene to a mixing means;
(b) passing the mixture from step (a) downflow through a fixed bed of hydrophillic coalescing media at a LHSV of 0.5 to 20, and coalescing in said bed a spent aqueous caustic phase from a kerosene;
(c) withdrawing said kerosene containing 0 to 10% of its original naphthenic acid content from a lower portion of said bed as a product of the process; and, (d) withdrawing said aqueous phase from the bottom of the charcoal bed.

15. A process for recovery of naphthenic acids from liquid hydrocarbons containing said acids which comprises:
(a) passing liquid hydrocarbons, and sufficient aque-ous base to neutralize the naphthenic acids, to a mixing means;
(b) passing the mixture from step (a) to a coalescing bed comprising a fixed bed of a hydrophillic media;
(c) absorbing on said media at least a portion of the neutralized naphthenic acids present in the liquid hydrocar-bon; and, (d) removing from said bed an aqueous phase comprising spent basic medium and a hydrocarbon phase comprising hydro-carbons depleted in naphthenic acid content.

16. Process of Claim 15 wherein the naphthenic acid salts absorbed on said bed are recovered by removing the bed from contact with the flowing hydrocarbon and aqueous streams, and treating said bed with high temperature steam to volatilize said acid salts.

17. Process of Claim 15 wherein the naphthenic acid salts absorbed on the charcoal bed are recovered by removing the bed from contact with the following hydrocarbon and aque-ous streams and treating said bed with an acid medium, thereby acidifying the naphthenic acids, and subsequently displacing said naphthenic acid from said bed with a desorbent.

18. Process of Claim 17 wherein 200 to 400 C steam is the desorbent.