United States Patent (19)
`Zarchy et al.
`
`11
`45
`
`Patent Number:
`Date of Patent:
`
`4,980,046
`Dec. 25, 1990
`
`54 SEPARATION SYSTEM FOR
`HYDROTREATEREFFLUENT HAVING
`REDUCED HYDROCARBON LOSS
`75 Inventors: Andrew S. Zarchy, Amawalk; Martin
`F. Symoniak, Mahopac, both of N.Y.;
`Robert S. Haizmann, Rolling
`Meadows, Ill.
`73) Assignee: UOP, Des Plaines, Ill.
`21 Appl. No.: 458,267
`22 Filed:
`Dec. 28, 1989
`51) Int. Cl. .............................................. C10G 67/06
`52 U.S. C. ...................................... 208/99; 208/100;
`208/213; 208/310 Z
`58) Field of Search ................. 208/99, 100, 212, 213,
`208/217, 188, 310 Z
`References Cited
`U.S. PATENT DOCUMENTS
`2,882,243 4/1959 Milton ..................................... 55/75
`2,897,141 7/1959 Honeycutt et al.........
`. 208/209
`3,714,031 1/1973 van der Toorn et al. .......... 208/213
`3,725,252 4/1973 Maier .................................. 208/213
`4,464,252 8/1984 Eberly, Jr. et al. ............ 208/244 X
`4,522,709 6/1985 Aldag et al. .................... 208/217 X
`4,627,910 2/1986 Millman .............................. 208/112
`4,741,819 5/1988 Robinson et al. ............... 208/212 X
`4,778,944 10/1988 Zarchy ............................ 585/751 X
`4,830,733 5/1989 Nagji et al. .
`... 208/302 X
`4,831,208 5/1989 Zarchy ................................ 585/737
`4,892,567 1/1990 Yan ......................................... 55/33
`Primary Examiner-Curtis R. Davis
`Assistant Examiner-William C. Diemler
`Attorney, Agent, or Firm-Thomas K. McBride; John G.
`Tolomei
`
`56
`
`ABSTRACT
`57
`A hydrotreating process uses a separation section that
`reduces the loss of C5 and higher hydrocarbons through
`the use of a low hydrogen to hydrocarbon ratio in the
`reactor and the adsorptive removal of a majority of
`hydrogen sulfide from a liquid phase hydrotreater efflu
`ent. Sulfurous hydrocarbon feed is admixed with hydro
`gen to maintain a hydrogen to hydrocarbon ratio of less
`than 50 SCFB. The hydrogen and hydrocarbons are
`passed through a hydrotreater reactor to convert sulfur
`compounds to H2S. The hydrotreater effluent is cooled
`and after flashing of any excess hydrogen or light ends
`the cooled effluent is contacted with an adsorbent mate
`rial for the removal of H2S. A hydrotreated hydrocar
`bon product is withdrawn from the adsorption section.
`The low hydrogen to hydrocarbon ratio permits the
`process to be used without the recycle of hydrogen
`thereby eliminating the need for separators and com
`pressors that were formerly used to recycle hydrogen
`to the hydrotreater. The elimination of the recycle and
`the low hydrogen to hydrocarbon ratio simplifies the
`flowscheme which can use a simple separator to flash
`light ends, hydrogen and some H2S from the hydro
`treater effluent. This process thus eliminates the need
`for a stripping section that was formerly needed to
`remove light ends and hydrogen sulfide from the hydro
`treated product. The adsorptive removal of the H2S and
`the limited venting of hydrogen allows essentially all of
`the hydrotreated product to be preserved. In most flow
`schemes H2S removal can be carried out in the absorb
`ers that are usually present for drying of the hydro
`treated feed.
`
`17 Claims, 1 Drawing Sheet
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`U.S. Patent
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`Dec. 25, 1990
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`4,980,046
`
`suu/n/03
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`FC
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`1.
`
`SEPARATION SYSTEM FOR HYDROTREATER
`EFFLUENT HAVING REDUCED HYDROCARBON
`LOSS
`
`4,980,046
`2
`concentrations but oxygen concentrations of less than
`0.1 ppm are also sought.
`Providing a high hydrogen to hydrocarbon ratio in
`the hydrotreatment zone complicates the arrangement
`of the process and presents a number of drawbacks. The
`use of a high hydrogen to hydrocarbon ratio adds signif
`icant cost to the operation. Typically, the high hydro
`gen to hydrocarbon ratio requires facilities for recover
`ing hydrogen and returning it to the hydrotreatment
`reactor. When hydrogen is recycled, a recycle com
`pressor, additional heat exchangers and extra cooling
`capacity are all required and add significant capital and
`operating expense to the process. The expense of the
`recycle facilities can be avoided by operating with
`once-through hydrogen, but at high hydrogen to hy
`drocarbon ratios once-through hydrogen is not eco
`nomical due to high losses of hydrogen and more im
`portantly, product that would occur without increasing
`the size and complexity of the product recovery facili
`tles.
`A conventional hydrotreating system will use separa
`tion facilities that include a separator, a stripper and
`usually an adsorption section. The adsorption section is
`typically used to remove water from the bottom frac
`tion of the stripper. The separator is typically used for
`the recovery of hydrogen that is recycled to the hydro
`treatment zone in order to supply most of the hydrogen
`that circulates through the hydrotreating section. The
`remaining portion of the hydrotreater effluent is taken
`from the separator in liquid phase and introduced into a
`stripper from which an overhead strean consisting
`primarily of light hydrocarbons and hydrogen sulfide
`gas is taken overhead to remove sulfur and light gases
`from the hydrotreatment zone while the remaining
`portion of the effluent is taken as a bottoms stream for
`further processing. The recycle of the entire gaseous
`stream, from the separator in order to recover hydro
`gen, forces all of the hydrogen sulfide gas to be re
`moved with the overhead from the stripper. The high
`gas volume that leaves the overhead from the stripper
`carries valuable product hydrocarbons away in a light
`gas stream. Since it is uneconomical to recover such
`hydrocarbons from the light gas stream, they are essen
`tially lost from the process. In addition, the high volume
`of hydrogen that circulates through the separator and
`hydrotreatment reactor increases the concentration of
`product hydrocarbons that are recirculated through the
`hydrotreatment reactor thereby resulting in a larger
`throughput through the reactor and loss of product
`hydrocarbons to side reactions such as cracking.
`It is an object of this invention to reduce the loss of
`product hydrocarbons by the separation of light gases
`and sulfur compounds from the effluent of a hydrotreat
`ent Zone.
`Another object of this invention is to provide a sepa
`ration section for a hydrotreatment process that has less
`equipment and complexity than those currently in use.
`Yet another object of this invention is to reduce the
`volumetric flow rate through a hydrotreatment reaction
`for a given volume of the hydrocarbons.
`A further object of this invention is the elimination of
`recycle facilities for maintaining a high hydrogen to
`hydrocarbon ratio in an a hydrotreatment zone.
`BRIEF DESCRIPTION OF THE INVENTION
`This invention is a hydrotreatment zone and separa
`tion section that uses a low hydrogen to hydrocarbon
`ratio in the hydrotreatment zone thereby eliminating
`
`BACKGROUND OF THE INVENTION
`This invention relates generally to the hydrotreat
`ment of hydrocarbons. This invention relates more
`specifically to the supply of hydrogen to a hydrotreat
`ment Zone and the separation of sulfur compounds from
`the hydrotreater effluent.
`DESCRIPTION OF THE PRIOR ART
`Hydrotreatment is a common method for the upgrad
`ing of feedstocks by the removal of contaminants such
`as sulfur, oxygen, and nitrogen. Hydrotreatment re
`moves contaminants from the feed that are objection
`able either in the end products or will interfere with the
`operation of processes that are used to treat or convert
`20
`the hydrocarbon feedstream. Sulfur is a particularly
`troublesome contaminant since it is often a poison for
`the catalyst in downstream processes, particularly plati
`num-containing catalysts, is corrosive to the process
`equipment and is objectionable in most hydrocarbon
`25
`products. In order to eliminate the adverse catalytic
`effects of sulfur compounds, it is often necessary to
`reduce these compounds to very low levels. In isomeri
`zation, for example, sulfur concentrations of less than
`0.5 ppm are needed. It is well known that organo-sulfur
`30
`and organo-oxygen compounds can be removed from
`hydrocarbon fractions by the use of hydrotreatment.
`Hydrotreatment feedstocks containing organo-sulfur
`compounds such as mercaptains, sulfides, disulfides and
`thiophenes are reacted with hydrogen to produce hy
`35
`drocarbons and hydrogen sulfide. It is also well known
`that the reaction of the organo-sulfur compounds is
`accelerated by the presence of catalysts comprising
`Group VIII metals and Group VIB metals supported on
`a refractory inorganic oxide. Hydrotreating also re
`moves oxygenate compounds by converting them into
`lower boiling hydrocarbons and water. The hydrogen
`sulfide and at least a portion of the water are typically
`removed in a stabilizer from which a purified hydrocar
`bon stream is recovered.
`45
`The desulfurization and deoxygenation of the hydro
`carbons in the hydrotreater is basically a hydrogenation
`process. In hydrogenation processes, the reaction rate is
`generally believed to be in proportion to the hydrogen
`partial pressure. As a result, conventional hydrotreating
`50
`processes tend to use a fairly high hydrogen to hydro
`carbon ratio.
`U.S. Pat. No. 4,627,910 issued to Milman teaches the
`hydrotreatment of light feeds including naphtha with a
`catalyst comprising Group VIII metal, phosphorus and
`cobalt on an alumina support at hydrotreatment condi
`tions including a temperature of from 400-950 F. and
`a pressure of from 20 to 6000 psig. The Milman refer
`ence also teaches that the process requires a minimum
`hydrogen circulation of 50 standard cubic feet per bar
`rel (SCFB) with much higher hydrogen to hydrocarbon
`circulations of 400-10,000 SCFB being preferred. The
`need to reduce contaminants to low concentration lev
`els has also led those skilled in the art to believe that a
`high hydrogen to hydrocarbon ratios are necessary in
`65
`order to achieve the desired degree of contaminant
`removal. For example, in isomerization processes, it is
`not only necessary to reduce sulfur compounds to low
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`O
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`15
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`4,980,046
`3
`4.
`the need for the recycle of hydrogen and allowing sul
`C5 and higher molecular weight hydrocarbons to con
`fur compounds to be withdrawn from the hydrotreat
`vert sulfur compounds to H2S and reduce the sulfur
`ment effluent in an adsorption zone. In the process of
`concentration of the hydrocarbon stream wherein the
`this invention, a sulfurous hydrogen-containing feed
`process includes the steps of admixing a sulfurous hy
`stream is contacted with a hydrotreatment catalyst at a
`drocarbon stream with a hydrogen stream in an amount
`low hydrogen concentration. It has been found that a
`that will produce a hydrogen to hydrocarbon ratio of
`high degree of sulfur conversion can be obtained at low
`less than 50 SCFB. The sulfurous hydrocarbon stream
`hydrogen to hydrocarbon ratios. This degree of sulfur
`and the hydrogen are contacted in a hydrotreating zone
`compound conversion allows desulfurization of the
`with a hydrotreating catalyst at hydrotreating condi
`feedstock to less than the necessary 0.5 ppm level. With
`tions to convert sulfur compounds to H2S and produce
`out the hydrogen recycle, the hydrotreatment zone
`a hydrotreated effluent stream. The hydrotreating zone
`operates with a hydrogen to hydrocarbon ratio of less
`can also convert oxygenate compounds to H2O. The
`than 50 SCFB and preferably in a range between 10 to
`amount of hydrogen that is admixed with the sulfurous
`40 SCFB. This low addition of hydrogen permits vent
`hydrocarbon stream is adjusted to produce a hydrogen
`ing of the hydrogen in the downstream separation sec
`to hydrocarbon ratio of less than 30 SCFB in the hydro
`tions without a significant loss of heavier hydrocarbons,
`treated effluent stream. The hydrotreated effluent
`such as pentanes, or an economic penalty in the cost of
`stream is cooled so that essentially all of the hydrogen
`the hydrogen lost. The downstream separation relies
`and hydrogen sulfide is adsorbed into a liquid phase of
`primarily on adsorptive separation of the hydrogen
`the hydrotreated effluent stream. The cooled hydro
`sulfide produced by the conversion of the sulfur com
`treated effluent stream is passed to an adsorption section
`pounds in the hydrotreatment zone. In most cases, the
`and contacted with an adsorbent material selective for
`separation facilities also include a single flash zone that
`H2S and a desulfurized hydrocarbon stream is recov
`separates the hydrogen from normally liquid hydrocar
`ered from the adsorption section. Additional details and
`bons. When the flash Zone is used, H2S will be removed
`embodiments of this invention are disclosed in the fol
`as a gas with the hydrogen as well as in the liquid phase
`25
`lowing detailed description.
`adsorption stream. The use of the lower hydrogen to
`hydrocarbon ratio is particularly advantageous in the
`BRIEF DESCRIPTION OF THE DRAWINGS
`separation section since it vents excess H2S; such vent
`FIG. 1 depicts a process arrangement for the process
`ing was not possible in the conventional flowscheme of
`of this invention.
`the prior art since the overhead from the flash zone
`contained too high of a concentration of valuable hy
`drocarbons. However, due to the much greater liquid
`volume, most of the H2S is removed adsorptively. It is
`believed that the adsorptive separation section will cost
`less than the conventional stripper of the prior art.
`However, aside from any decreased cost associated
`with providing an adsorptive separation for the H2S,
`additional product is recovered from the adsorptive
`separation section, product which would have been lost
`from the stripping section of the conventional hydro
`40
`treatment separation facilities. The additional cost of
`providing adsorptive separation is further minimized
`for many hydrotreatment arrangements that already
`provide an adsorptive separation for the removal of
`45
`Water.
`Accordingly, in one embodiment, this invention is a
`process for treating a sulfurous hydrocarbon stream
`comprising C5 and higher molecular weight hydrocar
`bons to convert sulfur compounds to H2S and reduce
`the sulfur concentration of the hydrocarbon stream.
`The process includes the steps of admixing a sulfurous
`hydrocarbon feedstream with a hydrogen stream to
`provide a hydrogen concentration in a range of from 10
`to 50 SCFB. The sulfurous hydrocarbon stream and
`hydrogen are contacted in a hydrotreating zone with a
`hydrotreating catalyst at hydrotreating conditions to
`convert sulfur compounds to H2S and produce a hydro
`treated effluent stream. The hydrotreated effluent
`stream is passed to a flash separator at conditions that
`will maintain a liquid phase containing at least 75 wt.%
`of the H2S and hydrogen from the hydrotreated effluent
`to produce an at least partially stabilized effluent. The
`partially stabilized effluent passes in liquid phase to an
`adsorption section where it is contacted with an adsor
`bent material selected for H2S. A desulfurized hydro
`65
`carbon stream is recovered from the adsorption section.
`In another embodiment, this invention is a process for
`treating a sulfurous hydrocarbon stream that comprises
`
`DETAILED DESCRIPTION OF THE
`INVENTION
`A basic understanding of this invention can be ob
`tained from FIG. 1 which shows a basic flowscheme for
`the process of this invention. The hydrocarbon feed
`enters the process by line 10 where it is admixed with
`make-up hydrogen from line 12. The combined feed and
`hydrogen are first heated in exchanger 14 and carried
`by line 16 to a heater 18 to further heat the feed and
`hydrogen to a reaction temperature. A line 20 carries
`the heated feed and hydrogen to a hydrotreater reactor
`22 from which the hydrotreated effluent is withdrawn
`by a line 24 and heat exchanged against the incoming
`feed in exchanger 14. A line 26 carries the partially
`cooled hydrotreater effluent from exchanger 14 to a
`cooler 28. A line 30 carries the cooled hydrotreater
`effluent from the exchanger 28 to a separator 32. Hy
`drogen, light hydrocarbon gases, and some H2S are
`withdrawn overhead from separator 32 by line 34 while
`the condensed liquids are carried by line 36 over to an
`adsorption section 38. The liquid hydrocarbon phase
`carried by line 36 enters an adsorption column 40 where
`it contacts an adsorbent material that adsorbs H2S and
`water to accomplish H2S removal and drying. The
`desulfurized and dried product is recovered by line 42
`from adsorption column 40. Once the adsorbent in the
`adsorbent column has become loaded with H2S and/or
`water, it undergoes desorption as shown for an adsor
`bent column 44. A hydrogen regeneration gas is heated
`in an exchanger 46 and carried by a line 48 into adsorp
`tion column 44. Water, H2S and regeneration gas are
`taken from adsorption column 44 by line 50, cooled in
`cooler 52 and removed from the process. Circulation of
`regeneration gas through adsorption column 44 contin
`ues until there is an essentially complete removal of H2S
`and water from the adsorbent material contained
`therein. A more complete description of feed compo
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`4,980,046
`6
`5
`nents, product components and the conditions in the
`metallic elements from both Group VIII and Group
`operational zones are hereinafter described.
`VIB of the Periodic Table have been found to be partic
`The feeds that will benefit from this process will
`ularly useful. Group VIII elements include iron, cobalt,
`contain sulfur and in many cases oxygen compounds
`nickel, ruthenium, rhenium, palladium, osmium, indium
`and platinum with cobalt and nickel being particularly
`which will interfere with downstream operations. Sul
`fur contaminants are present with the original crude oil
`preferred. The Group VIB metals consist of chromium,
`molybdenum and tungsten, with molybdenum and
`fraction and include mercaptans, sulfides, disulfides and
`tungsten being particularly preferred. The metallic
`thiophenes. In the light straight-run feeds, sulfur con
`components are supported on a porous carrier material.
`centrations will usually range from 20 to 300 ppm. Al
`though light straight-run feeds generally contain few
`The carrier material may comprise alumina, clay or
`10
`naturally occurring oxygenate compounds, contamina
`silica. Particularly useful catalysts are those containing
`tions from other process can introduce significant
`a combination of cobalt or nickel metals from 2 to 5 wt.
`amounts of oxygenate compounds such as alcohols,
`% and from 5 to 15 wt.% molybdenum on an alumina
`support. The weight percentages of the metals are cal
`ethers, aldehydes and ketones in feedstocks. These oxy
`genate contaminants can also be removed by the hydro
`culated as though they existed in the metallic state.
`Typical commercial catalysts comprise spherical or
`treatment process herein disclosed.
`extruded alumina based composites impregnated with
`The feedstock is first mixed with a hydrogen-contain
`Co-Mo or Ni-Mo in the proportions suggested above.
`ing gas stream. Preferably, the gas stream will contain at
`least 50 wt.% hydrogen. More preferably, the hydro
`The ABD of commercial catalysts generally range from
`gen-containing gas stream will have a concentration
`0.5 to 0.9 g/cc with surface areas ranging from 150 to
`250 m2/g. Generally, the higher the metals content on
`greater than 75 wt.% hydrogen. Hydrogen-producing
`the catalyst, the more active the catalyst.
`processes from which the gas stream is obtained can
`contain relatively large amounts of light hydrocarbons.
`Effluent from the hydrotreatment reactor enters one
`or more stages of cooling to condense most of the vapor
`These light hydrocarbons are undesirable since their
`product into a liquid phase product stream. The concen
`presence can increase the loss of product in downstream
`25
`tration of hydrogen in the effluent from the hydro
`separation facilities and increases the mass volume
`through downstream processes. Therefore, hydrogen
`treater will usually be on the order of 4 mol. % and
`containing gas streams of relatively pure hydrogen are
`preferably will have a hydrogen concentration of 2 mol.
`preferred.
`%. Conversion of the sulfur in the hydrotreater zone
`will be approximately 99.9% such that essentially all the
`The feedstocks that can be used in this invention
`include hydrocarbon fractions rich in C4-C7 paraffins.
`sulfur has now been converted to H2S. For this purpose,
`The term "rich' is defined to mean a stream having
`the effluent from the hydrotreatment reactor will be
`cooled to a temperature of from 550 to 100 F. This
`more than 50% of the mentioned component. Preferred
`cooling will cause a large portion of the H2S and hydro
`feedstocks are substantially pure paraffin streams hav
`gen to be absorbed in the liquid phase of the hydrotreat
`ing from 4 to 6 carbon atoms or a mixture of such sub
`35
`stantially pure paraffins. Other useful feedstocks include
`ment effluent. In one form of this invention, the hydro
`light natural gasoline, light straight-run naphtha, light
`gen concentration is low enough to condense essentially
`raffinates, light reformate, light hydrocarbons, field
`all of the effluent from the hydrotreatment reactor. In
`these cases there will be an essentially liquid phase hy
`butanes, and straight-run distillates having distillation
`drotreatment effluent stream that can be passed directly
`end points of about 170 F. (77. C.) and containing
`substantial quantities of C4-C6 paraffins. The feed
`to an adsorption section for the removal of H2S and
`other contaminants. In most cases, however, cooling of
`stream may also contain low concentrations of unsatu
`rated hydrocarbons and hydrocarbons having more
`the hydrotreatment effluent will still leave a vapor
`phase portion that will consist primarily of hydrogen,
`than 7 carbon atoms.
`H2S, light hydrocarbons, and possibly water as well as
`The gas stream is mixed with the feed in proportions
`45
`that will produce a hydrogen to hydrocarbon ratio of
`other contaminants. The hydrocarbons in the gaseous
`phase will be light gases that can include C1-C3 hydro
`not more than 50 SCFB (8.8 stdm3/m3). The hydro
`treatment zone of this invention can be operated with
`carbons which may have entered with the feed or were
`produced by a minor degree of hydrocracking. The
`hydrogen concentrations as low as 10 SCFB (1.8
`majority of the H2S leaving the hydrotreater reactor
`stdm/m3). A hydrogen concentration of 10 SCFB (1.8
`stdm/m) provides hydrogen for chemical demands
`will be in the liquid phase of the cooled hydrotreater
`effluent. Although equilibrium favors a relatively
`which, require very small amounts of hydrogen for the
`higher concentration of H2S in the gaseous phase, the
`desulfurization and deoxygenation reactions, and suffi
`proportion of liquid to vapor in the effluent is very high
`cient hydrogen partial pressure to drive the reaction.
`so that the majority of the H2S is in the liquid phase.
`Hydrogen concentrations above 50 SCFB (8.8
`55
`stdm3/m3) in the reaction zone interfere with the eco
`Where there is a substantial vapor phase, the cooled
`hydrotreater effluent will enter a separation zone. The
`nomical operation of the process.
`separation zone divides the hydrogen and light gases
`The feed is heated and then enters a hydrotreatment
`from the liquid phase. Preferably, the separation zone
`reactor. Conditions within the reaction Zone typically
`include a temperature in the range of 390-650 F.
`will consist of a simple flash drum. The main purpose of
`the flash removal section is to remove light ends and
`(200-350 C.), a pressure of from 100 to 800 kPa and a
`any hydrogen. The flash separator is usually operated at
`liquid hourly space velocity of from 1 to 20. Typically,
`a pressure in a range of from 250 to 450 psig. Since the
`the reaction conditions are selected to keep the hydro
`H2S is removed by adsorption in later stages, the only
`carbon feed in a vapor phase.
`The hydrotreatment reactor contains a fixed bed of
`function of the flash separator is the removal of the
`65
`hydrotreatment catalyst. Catalytic composites that can
`hydrogen and light ends to obtain a liquid phase, hydro
`carbon stream for adsorption. Since the amount of hy
`be used in this process include traditional hydrotreating
`drogen entering the separation is low, there is only a
`catalysts. Combinations of clay and alumina-containing
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`4,980,046
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`8
`small amount of hydrogen and light gases that are re
`Preferred adsorbents for H2S and water removal are 4A
`type sieves.
`moved overhead from the separator. The low volume
`of hydrogen and other gases going overhead from the
`In a preferred form, the adsorbent material is readily
`separator limits the loss of higher hydrocarbons such as
`regenerable and the adsorption zone is designed for the
`regeneration of the adsorbent material. Adsorption sys
`C5's.
`The adsorption section receives an essentially liquid
`tems using two or more regeneration columns such that
`phase stream either directly from the hydrotreater efflu
`one adsorption column is used for the adsorption while
`another column is in one or more stages of regeneration
`ent coolers or from the separation section. In this inven
`tion, the primary function of the adsorption section is to
`are well known to those skilled in the art. In most pro
`cess arrangements for this invention, the adsorption
`adsorb H2S and thereby eliminate the stripper that was
`material will be regenerated using a regeneration gas in
`otherwise needed in the separation section of prior art
`hydrotreater separation sections. Without the stripper
`a multiple bed adsorption system. Suitable regeneration
`gases for this purpose will include hydrogen and hydro
`section, there is essentially no loss of Cs and higher
`hydrocarbons from the liquid phase of the hydrotreater
`carbon streams. The figure shows a typical regeneration
`system where a regeneration gas is heated to a tempera
`effluent. The adsorption section, in most cases, will also
`ture in a range of 450-600 F. and passed through a
`be designed to adsorb water as well as H2S. In most
`applications of this process, an adsorption section
`regeneration zone to desorb hydrogen sulfide and water
`would normally be present anyway for the removal of
`from the adsorbent material. Pressure in the adsorption
`column is usually reduced to about 100 psi or less in
`water so that all that is needed is the addition of addi
`order to increase desorption. The adsorption stream
`tional capacity for the removal of H2S. As a result, the
`20
`use of an adsorption section to remove H2S poses only
`leaving the adsorption column is further cooled to a
`temperature of between 80 to 100' F.
`minor increases in the cost of the separation section. In
`The desorbent stream can undergo further separation
`fact, the removal of H2S from the adsorption section
`may not impose any penalty on the operation of adsorp
`for the removal of H2S and, when present, water from
`the regeneration gas for its reuse in the desorption stage.
`tion driers. A typical adsorbent for drying, such as a 4A
`25
`type molecular sieve, has a greater selectivity for water
`However, in most cases, the desorbent stream will not
`be recycled directly to the adsorption section. Where a
`than H2S. Since water first is adsorbed, the extra adsor
`bent for the removal of H2S provides an extended mass
`hydrocarbon stream is used as the desorbent, the H2S
`loaded stream may be passed to the separation facilities
`transfer Zone for reducing the residual concentration of
`for another process. For example, the hydrocarbon
`water that will leave the adsorption section. Since
`30
`downstream processes, such as isomerization, are usu
`desorbent stream can be passed to the crude unit of a
`ally more sensitive to water, additional adsorbent pro
`refinery where H2S and water can be removed and the
`rest of the hydrocarbon stream is recycled. Alternately,
`vides the benefit of insuring that water concentrations
`the desorbent stream can be passed to a gas treatment
`are low.
`This invention does not require the use of any partic
`facilities such as an FCC gas concentration section. The
`ular adsorbent material. Any adsorbent that has a high
`relatively low volume of the desorbent material makes
`it possible to handle this stream in a variety of ways
`capacity and selectivity for H2S will be suitable for the
`which will be readily appreciated by those skilled in the
`use of this invention in its most basic form. Preferred
`adsorbents for this invention consist of molecular sieve
`art.
`adsorbents with a pore size below 4 angstroms and
`above 3.6 angstroms, and more specifically adsorbents
`such as sodium A and clinoptilolite are representative
`samples of suitable adsorbents. Typically, the adsorbent
`material will also have a capacity for water removal.
`
`10
`
`15
`
`35
`
`EXAMPLE
`The following example is provided to show the oper
`ation of the hydrotreatment system of this invention.
`This example is based on engineering calculations and
`actual operating experience from similar components
`and other hydrotreatment and adsorption processes.
`
`45
`
`LINE NO.
`COMPONENTS LBS/HR
`WATER
`HYDROGEN SULFIDE
`PROPYLMERCAPTAN
`HYDROGEN
`METHANE
`ETHANE
`PROPANE
`I-BUTANE
`N-BUTANE
`I-PENTANE
`N-PENTANE
`CYCLOPENTANE
`2,2-DIMETHYLBUTANE
`2,3-DIMETHYLBUTANE
`2-METHYPENTANE
`3-METHYPENTANE
`N-HEXANE
`METHYLCYCLO.
`PENTANE
`
`Once
`Thru
`Reactor
`Fresh
`Feed Effluent Hydrogen Vent
`O
`24
`12
`34
`
`Adsorber
`Feed
`36
`
`Product
`42
`
`8
`
`45
`-
`---
`
`O
`44
`6730
`12032
`6
`18
`590
`533
`3346
`9895
`4464
`
`8
`21
`
`54
`O
`18
`42
`14
`453
`633
`12034
`1161.
`81
`590
`5343
`3346
`9895
`4464
`
`---
`
`55
`O
`8
`16
`4.
`6
`3
`2
`
`m
`12
`
`-
`
`30
`2
`
`---
`2
`11
`5
`1.
`
`3
`2
`4
`2
`
`7
`20
`wa
`25
`8
`17
`42
`14
`451
`6722
`12O18
`1160
`181
`590
`5340
`3344
`989
`4462
`
`-----
`
`25
`8
`17
`42
`14
`451
`6722
`12O18
`60
`18
`590
`5340
`3344
`9891
`4462
`
`6 of 8
`
`REFINED TECHNOLOGIES, INC.
`EXHIBIT 2005
`
`

`

`10
`
`9
`
`4,980,046
`
`-continued
`Once
`Thru
`Reactor
`Fresh
`Feed Effluent Hydrogen Vent
`O
`24
`12
`34
`
`1709
`519
`1180
`47648
`
`1709
`519
`1180
`47775
`
`127
`
`76
`
`Adsorber
`Feed
`36
`
`1708
`519
`118O
`
`Product
`42
`
`708
`59
`180
`47673
`
`LNE NO.
`
`CYCLOHEXANE
`BENZENE
`2-METHYLHEXANE
`TOTAL
`
`Referring again to FIG. 1, a feed having a composi
`tion given in the Table for line 10 is admixed with a
`hydrogen-containing stream. The hydrogen stream 15
`contains primarily hydrogen and light gases as de
`scribed in the Table for line 12. The feed and hydrogen
`are first heated in exchanger 14 to a temperature of
`about 475 F. and then further heated in heater 18 to a
`temperature of 550 F. The heated feed and hydrogen 20
`mixture enters the hydrogen reactor at a pressure of 360
`psig. The hydrotreater reactor contains a commercial
`cobalt-molybdenum type hydrotreatment catalyst that
`the feed contacts at a weight hourly space velocity of 8.
`The hydrotreater effluent recovered from the hydro- 25
`treater reactor has the composition given in the Table
`for line 24. Passage of the feed through the hydrotreater
`achieves an essentially complete conversion of sulfur
`containing compounds to H2S. The hydrotreater efflu
`ent is cooled in heat exchangers in exchanger 14 and 28 30
`to a temperature of 100 F. In flash drum 32, the cooled
`hydrotreater effluent is separated into an overhead vent
`stream having the composition given for line 34 in the
`table and a liquid stream having a composition given for
`line 36. The separator liquid is passed to an adsorption 35
`column containing approximately 3500/lbs of a 4A type
`adsorbent and passed through the column at a tempera
`ture of 100 F. and a pressure of 350 psig. A dried and
`sulfur-free product stream having a composition given
`in the table under line 42 is removed from the adsorbent 40
`column. While the separator liquid passes through one
`of the adsorber vessels, another adsorber vessel is regen
`erated in a series of regeneration steps. These regenera
`tion steps include a