METHODS FOR HYDROGEN SULFIDE RECYCLING USING SELECTIVE SOLVENTS IN THE HYDROPROCESSING OF RENEWABLE FEEDSTOCKS

Abstract

Methods for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks are provided. An exemplary method includes the steps of combining hydrogen sulfide with renewable hydrocarbon feedstocks to form a first stream, deoxygenating the first stream to form a second hydrocarbon stream comprising deoxygenated hydrocarbons, water, carbon dioxide, and hydrogen sulfide, and separating the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising carbon dioxide and hydrogen sulfide. The method further includes the steps of selectively scrubbing the hydrogen sulfide from the third recycle stream to form a fourth recycle stream comprising carbon dioxide and a fifth recycle stream comprising hydrogen sulfide and selectively scrubbing the carbon dioxide from the fourth recycle stream.

Description

TECHNICAL FIELD

The technical field generally relates to methods for hydroprocessing renewable feedstocks. More particularly, the technical field relates to methods for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks.

BACKGROUND

As the demand for fuels such as diesel fuel and aviation fuel increases worldwide, there is increasing interest in sources other than petroleum crude oil for producing the fuel. One source is renewable feedstocks including, but not limited to, plant oils such as corn, jatropha, camelina, rapeseed, canola, soybean and algal oils, animal fats such as tallow, fish oils, and various waste streams such as yellow and brown greases and sewage sludge. The common feature of these feedstocks is that they are composed of mono- di- and tri-glycerides, and free fatty acids (FAA). Another class of compounds appropriate for these processes is fatty acid alkyl esters (FAAE), such as fatty acid methyl ester (FAME) or fatty acid ethyl ester (FAEE). These types of compounds contain aliphatic carbon chains generally having from about 8 to about 24 carbon atoms. The aliphatic carbon chains in the glycerides, FFAs, or FAAEs can be saturated or mono-, di- or poly-unsaturated. Most of the glycerides in the renewable feed stocks will be triglycerides, but some may be monoglycerides or diglycerides. The monoglycerides and diglycerides can be processed along with the triglycerides.

In the hydroprocessing of renewable feedstocks, sulfided catalysts (e.g., NiMo, CoMo, NiCoMo) are used to perform primarily deoxygenation reactions that produce CO₂ and H₂O. The water in particular may detrimentally strip the catalyst of the sulfide (or oxidize the metal), which negatively impacts catalyst activity and stability. Since renewable feedstocks are typically low in sulfur, in prior art processes, a sulfur dopant such as DMDS is added to the system. For a typical hydroprocessing unit size of about 90,000,000 gallon/year, this represents an operating cost of up to about $2.5 MM/yr.

In other prior art processes, other sources such as an H₂S rich sour gas may be used. Exemplary schemes may include the recycle of H₂S. One particular problem of such processes, however is that the CO₂ that is generated must be removed from the recycle gas system, and many amines/basic solvents that would be provided to remove the CO₂ will also remove H₂S, which is the stronger acid. Hence, a relatively pure H₂S recycle stream has been difficult to achieve in such processes.

Accordingly, it is desirable to provide improved renewable feedstock hydroprocessing techniques. In addition, it is desirable to provide such methods including the recycling of hydrogen sulfide using a recycle stream that is relatively free of carbon dioxide. Furthermore, other desirable features and characteristics of the present invention will become apparent from the subsequent detailed description and the appended claims, taken in conjunction with the accompanying drawings and this background.

BRIEF SUMMARY

Methods for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks are provided herein. In accordance with an exemplary embodiment, a method includes the steps of combining hydrogen sulfide with hydrogen rich recycle gas and renewable hydrocarbon feedstocks to form a first stream, deoxygenating the first stream to form a second hydrocarbon stream comprising recycle gas, deoxygenated hydrocarbons, water, carbon dioxide, and hydrogen sulfide, and separating the recycle gas, carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide and hydrogen sulfide. The method further includes the steps of selectively scrubbing the hydrogen sulfide from the third recycle stream to form a fourth recycle stream comprising recycle gas and carbon dioxide and a fifth recycle stream comprising hydrogen sulfide and scrubbing the carbon dioxide from the fourth recycle stream.

In another exemplary embodiment, a method includes the steps of combining hydrogen sulfide with a hydrogen rich recycle gas and renewable hydrocarbon feedstocks to form a first stream, deoxygenating the first stream to form a second hydrocarbon stream comprising recycle gas, deoxygenated hydrocarbons, water, carbon dioxide, and hydrogen sulfide, and separating the recycle gas, carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide and hydrogen sulfide. The method further includes the steps of scrubbing the hydrogen sulfide and the carbon dioxide from the third recycle stream to form a fourth acid gas stream comprising hydrogen sulfide and carbon dioxide and a fifth recycle stream comprising recycle gas, and selectively separating and enriching the fourth acid gas stream to form a sixth recycle stream comprising hydrogen sulfide.

In accordance with yet another exemplary embodiment, a system for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks includes a deoxygenation reactor that deoxygenates a first stream comprising hydrogen sulfide, hydrogen-rich recycle gas, and renewable hydrocarbon feedstocks to form a second hydrocarbon stream comprising deoxygenated hydrocarbons, water, recycle gas, carbon dioxide, and hydrogen sulfide, and a phase separator that separates the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide, and hydrogen sulfide. The system further includes a first scrubbing unit that selectively scrubs the hydrogen sulfide from the third recycle stream to form a fourth recycle stream comprising recycle gas and carbon dioxide and a fifth recycle stream comprising hydrogen sulfide, and a second scrubbing unit that selectively scrubs the carbon dioxide from the fourth recycle stream.

DETAILED DESCRIPTION OF THE DRAWINGS

The various embodiments will hereinafter be described in conjunction with the following drawing figures, wherein like numerals denote like elements, and wherein:

FIG. 1 is an illustration of an exemplary renewable feedstock hydroprocessing flowscheme that is suitable for use in implementing embodiments of the present disclosure;

FIG. 2 is an illustration of a system implementing a method for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks according to an exemplary embodiment; and

FIG. 3 is an illustration of a system implementing a method for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks according to another exemplary embodiment.

DETAILED DESCRIPTION

The following detailed description is merely exemplary in nature and is not intended to limit the various embodiments or the application and uses thereof. Furthermore, there is no intention to be bound by any theory presented in the preceding background or the following detailed description.

Various embodiments described herein are directed to methods for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks. In one embodiment described in connection with FIG. 2, in the context of a hydrogen-rich recycle gas (e.g., including at least about 50 vol. % H₂, along with smaller (e.g., less than about 10% each) CO, propane, methane, nitrogen, and other light hydrocarbons, and of course the subject H₂S and CO₂ gasses), an H₂S-selective solvent is used in a first recycle gas scrubber. The solvent regeneration produces a stream concentrated in H₂S and dilute in CO₂ for recycle back to the reactor section (e.g., via acid gas compression or reaction with or dissolving into fresh feed). A second scrubber using a solvent suitable for CO₂ removal is then used to remove the remaining acid gas. In another embodiment described in connection with FIG. 3, a single solvent is used in the hydrogen-rich recycle gas (and off-gas/LPG scrubbers) of an acid gas removal (AGR) system for H₂S and CO₂ removal, followed by an acid gas enrichment (AGE) system with a solvent highly selective for H₂S and CO₂ separation. Solvents such as Ucarsol™ AP-814 are suitable for CO₂ removal in the AGR system and solvents such as Ucarsol™ HS-103 are suitable for H₂S concentration in the AGE system (both solvents being available from the Dow Chemical Company of Midland, Mich., USA). In embodiments wherein it is desirable to provide a concentrated H₂S stream to a Claus Process system (as known in the art, the Claus Process is provided for recovering elemental sulfur from gaseous hydrogen sulfide), it has been discovered that the Ucarsol™ AGE system solvent is not selective enough to provide an H₂S stream concentrated enough for direct feed to a Claus Process or recycle to the hydroprocessing process. In prior art systems, two stages of AGE would have been provided for a highly-concentrated H₂S recycle stream. In the present embodiment described in connection with FIG. 3, however, a sterically-hindered amine system, which has superior selectivity, is provided and allows for the recycle of H₂S with a single stage of AGE.

As initially noted, the term renewable feedstock is meant to include feedstocks other than those obtained directly from petroleum crude oil. Another term that has been used to describe this class of feedstocks is renewable fats and oils. The renewable feedstocks that can be used in the present disclosure include any of those that include glycerides and free fatty acids (FFA). Examples of these feedstocks include, but are not limited to, canola oil, corn oil, soy oils, rapeseed oil, soybean oil, colza oil, tall oil, sunflower oil, hempseed oil, olive oil, linseed oil, coconut oil, castor oil, peanut oil, palm oil, mustard oil, cottonseed oil, tallow, yellow and brown greases, lard, train oil, fats in milk, fish oil, algal oil, sewage sludge, cuphea oil, camelina oil, jatropha oil, curcas oil, babassu oil, palm kernel oil, crambe oil, and the like. Biorenewable is another term used to describe these feedstocks. The glycerides, FFAs, and fatty acid alkyl esters, of the typical vegetable oil or animal fat contain aliphatic hydrocarbon chains in their structure which have about 8 to about 24 carbon atoms with a majority of the oils containing high concentrations of fatty acids with 16 and 18 carbon atoms. Mixtures or co-feeds of renewable feedstocks and fossil fuel derived hydrocarbons may also be used as the feedstock. Other feedstock components may be used if the carbon chain length is well-defined before mixing with renewable oils to allow meeting desired yields and specifications for diesel and aviation range paraffins.

In a generalized hydroprocessing scheme, the renewable feedstocks are flowed to a reaction zone or stage comprising one or more catalyst beds in one or more reactor vessels. Within the reaction zone or stage, multiple beds or vessels may be employed, and where multiple beds or vessels are employed, inter-stage product separation may or may not be performed between the beds or vessels. The term feedstock is meant to include feedstocks that have not been treated to remove contaminants, as well as those feedstocks purified in a pretreatment zone or an oil processing facility. The renewable feedstocks, with or without additional liquid recycled from one or more product streams, may be mixed in a feed tank upstream of the reaction zone, mixed in the feed line to the reactor, or mixed in the reactor itself. In the reaction zone, the renewable feedstocks are contacted with a multifunctional catalyst or set of catalysts comprising deoxygenation, hydrogenation, isomerization, and hydrocracking functions in the presence of hydrogen.

A number of reactions occur concurrently within the reaction zone. The order of the reactions is not critical to the described embodiments, and the reactions may occur in various orders. One reaction occurring in the reaction zone is hydrogenation to saturate olefinic compounds in the reaction mixture. Another type of reaction occurring in the reaction zone is deoxygenation. The deoxygenation of the mixture may proceed through different routes such as decarboxylation, where the feedstock oxygen is removed as carbon dioxide, decarbonylation, where the feedstock oxygen is removed as carbon monoxide, and/or hydrodeoxygenation, where the feedstock oxygen is removed as water. Decarboxylation, decarbonylation, and hydrodeoxygenation are herein collectively referred to as deoxygenation reactions.

Accordingly, as shown in FIG. 1, one (non-limiting) example of a renewable feedstock hydroproces sing flowscheme is provided to serve as an example of the type of processes in which the described embodiments of the present disclosure (FIGS. 2 and 3) may be implemented. Within this flowscheme, the renewable feedstock as described above enters via stream 11, wherein it is mixed with a sulfiding agent (e.g., H₂S as described above) that enters via stream 12. The combined stream 9 then further combines with sweet recycle gas stream 8 including recycled H₂ (as will be described below) to become stream 13, which then proceeds to the reaction zone of the flowscheme, which as noted above may include a plurality of reactors for a plurality of different reaction functionalities. In FIG. 1, three reactors R1-R3 are illustrated.

With attention first to the guard reactor R1, it is known that renewable feedstocks that can be used in the present disclosure may contain a variety of impurities. For example, tall oil is a by-product of the wood processing industry and tall oil contains esters and rosin acids in addition to FFAs. Rosin acids are cyclic carboxylic acids. The renewable feedstocks may also contain contaminants such as alkali metals, e.g. sodium and potassium, phosphorous as well as solids, water and detergents. An optional first step is to remove as much of these contaminants as possible. One possible pretreatment step involves contacting the renewable feedstock with an ion-exchange resin in a pretreatment zone at pretreatment conditions. The ion-exchange resin is an acidic ion exchange resin such as Amberlyst™-15 and can be used as a bed in a reactor through which the feedstock is flowed through, either upflow or downflow.

Another possible means for removing contaminants is a mild acid wash. This is carried out by contacting the feedstock with an acid such as sulfuric, nitric or hydrochloric acid in a reactor. The acid and feedstock can be contacted either in a batch or continuous process. Contacting is done with a dilute acid solution usually at ambient temperature and atmospheric pressure. If the contacting is done in a continuous manner, it is usually done in a counter current manner. Yet another possible means of removing metal contaminants from the feedstock is through the use of guard beds (R1) which are well known in the art. These can include alumina guard beds either with or without demetallation catalysts such as nickel or cobalt. Filtration and solvent extraction techniques are other choices which may be employed. Hydroprocessing such as that described in U.S. Ser. No. 11/770,826, incorporated by reference, is another pretreatment technique which may be employed.

After pre-treating guard reactor R1, the renewable feedstock passes via line 14 to the deoxygenation reaction R2. The feedstock is flowed to a reaction zone comprising one or more catalyst beds in one or more reactors. The term feedstock is meant to include feedstocks that have not been treated to remove contaminants as well as those feedstocks purified in a pretreatment zone. In the reaction zone R2, the feedstock is contacted with a hydrogenation or hydrotreating catalyst in the presence of hydrogen at hydrogenation conditions to hydrogenate the olefinic or unsaturated portions of the n-paraffinic chains. Hydrogenation or hydrotreating catalysts are any of those well known in the art such as sulfide nickel or nickel/molybdenum dispersed on a high surface area support, as initially noted above. Hydrogenation conditions include a temperature of about 200° C. to about 300° C. and a pressure of about 1379 kPa absolute (200 psia) to about 4826 kPa absolute (700 psia). Other operating conditions for the hydrogenation zone are well known in the art.

The hydrogenation and hydrotreating catalysts enumerated above are also capable of catalyzing decarboxylation, decarbonylation, and/or hydrodeoxygenation of the feedstock to remove oxygen. Decarboxylation, decarbonylation, and hydrodeoxygenation are herein collectively referred to as deoxygenation reactions. Decarboxylation and decarbonylation conditions include a relatively low pressure of about 3447 kPa (500 psia) to about 6895 kPa (1000 psia), a temperature of about 288° C. to about 450° C. and a liquid hourly space velocity of about 1 to about 4 hr⁻¹. Since hydrogenation is an exothermic reaction, as the feedstock flows through the catalyst bed the temperature increases and decarboxylation and hydrodeoxygenation will begin to occur.

The reaction product from the deoxygenation reactions in the deoxygenation zone R2 will include a liquid portion and a gaseous portion present in stream 15. The liquid portion includes a hydrocarbon fraction which is essentially all n-paraffins and having a large concentration of paraffins in the range of about 9 to about 18 carbon atoms. Different feedstocks will result in different distributions of paraffins. Although this hydrocarbon fraction is useful as a diesel fuel, because it comprises essentially all n-paraffins, it will have poor cold flow properties. If it is desired to improve the cold flow properties of the liquid hydrocarbon fraction, then the entire reaction product can be contacted with an isomerization catalyst in isomerization reaction zone R3 under isomerization conditions to at least partially isomerize the n-paraffins to isoparaffins. Catalysts and conditions for isomerization are well known in the art. See for example US 2004/0230085 A1 which is incorporated by reference in its entirety.

The gaseous and liquid products in line 15 may be separated using a suitable phase separation apparatus 18, resulting in a liquid product line 2 and a gaseous product line 19. Accordingly, some (or all) of the product of the deoxygenation reaction zone (after separation processes) in line 2 is contacted with an isomerization catalyst in the presence of hydrogen at isomerization conditions to isomerize the normal paraffins to branched paraffins in reactor R3.

The isomerization of the paraffinic product can be accomplished in any manner known in the art or by using any suitable catalyst known in the art. Suitable catalysts comprise a metal of Group VIII (IUPAC8-10) of the Periodic Table and a support material. Suitable Group VIII metals include platinum and palladium, each of which may be used alone or in combination. The support material may be amorphous or crystalline. Suitable support materials include amorphous alumina, amorphous silica-alumina, ferrierite, ALPO-31, SAPO-11, SAPO-31, SAPO-37, SAPO-41, SM-3, MgAPSO-31, FU-9, NU-10, NU-23, ZSM-12, ZSM-22, ZSM-23, ZSM-35, ZSM-48, ZSM-50, ZSM-57, MeAPO-11, MeAPO-31, MeAPO-41, MeAPSO-11, MeAPSO-31, MeAPSO-41, MeAPSO-46, ELAPO-11, ELAPO-31, ELAPO-41, ELAPSO-11, ELAPSO-31, ELAPSO-41, laumontite, cancrinite, offretite, hydrogen form of stillbite, magnesium or calcium form of mordenite, and magnesium or calcium form of partheite, each of which may be used alone or in combination.

Isomerization conditions include a temperature of about 150° C. to about 360° C. and a pressure of about 1034 kPa absolute (150 psia) to about 2068 kPa absolute (300 psia) or about 1724 kPa absolute (250 psia) to about 4726 kPa absolute (700 psia). In another embodiment the isomerization conditions include a temperature of about 300° C. to about 360° C. and a pressure of about 3102 kPa absolute (450 psia) to about 3792 kPa absolute (550 psia). The final effluent stream, i.e. the stream obtained after all reactions have been carried out, shown in FIG. 1 as stream 16, noted above, is now processed through a phase separator 6 to obtain a gaseous stream 3 and a liquid product stream 20, which may then be distilled in a suitable distillation apparatus 7 to obtain one or more product fraction (e.g., 4, 5), which may include diesel, jet, naphtha, and other like product fractions. Various integration schemes between the two separators can be employed as may be found advantageous in conserving energy or equipment pieces.

The separated gaseous component from separation apparatus 18 (stream 19) includes CO₂ and H₂S, and of course hydrogen gas for recycling. Accordingly, stream 19 will be the subject of the embodiments described below in FIGS. 2 and 3. The separated liquid component 20 includes the product hydrocarbon stream useful as a diesel and/or jet fuel. Further separations may be performed to remove naphtha and LPG from the product hydrocarbon stream, as illustrated in FIG. 1. Subsequent to processing according to one of the embodiments in either FIG. 2 or 3, recycle gas stream 8 may be recycled as indicated in FIG. 1 for further uses in the above-described processes.

As initially noted above, sulfided catalysts (e.g., NiMo, CoMo, NiCoMo) are used to perform primarily deoxygenation reactions that produce CO₂ and H₂O. The water in particular may detrimentally strip the catalyst of the sulfide (or oxidize the metal), which negatively impacts catalyst activity and stability. Since renewable feedstocks are typically low in sulfur, in prior art processes, a sulfur dopant such as DMDS is added to the system. Other sources such as an H₂S rich sour gas may be used. Exemplary schemes may include the recycle of H₂S. One particular problem of such processes, however is that the CO₂ that is generated must be removed from the recycle gas system, and many amines/basic solvents that would be provided to remove the CO₂ will also remove H₂S, which is the stronger acid. Hence, a relatively pure H₂S recycle stream has been difficult to achieve in such processes.

With attention now to FIG. 2, disclosed is one embodiment that serves to address the above-noted problem of catalyst deactivation and H₂S recycling in renewable feedstock hydroprocessing. FIG. 2 is directed to an embodiment wherein an H₂S-selective solvent is used in a first recycle gas scrubber. The solvent regeneration produces a stream concentrated in H₂S and dilute in CO₂ for recycle back to the reactor section (e.g., via acid gas compression or reaction with or dissolving into fresh feed). A second scrubber using a solvent suitable for CO₂ removal is then used to remove the remaining acid gas.

For ease of illustration, the reaction and separation zones described above in FIG. 1 have been condensed into a single box 21 in FIG. 2. From box 21, the stream 19 including the sour recycle gas (H₂ with CO₂, H₂S) is passed to an H₂S-selective scrubber unit 22. The H₂S-selective scrubber unit 22 includes an H₂S-selective solvent. Various H₂S-selective solvents are known to those having ordinary skill in the art, and may be included for use in the unit 22. Suitable solvents of this type include, but are not limited to: Flexsorb SE or SE PLUS™ from ExxonMobil Research and Engineering (EMRE). The H₂S-selective scrubber unit 22 is provided in communication with an H₂S-selective solvent regeneration unit 23. Stream 24 passes rich solvent to the H₂S-selective solvent regeneration unit 23, and stream 25 passes regenerated solvent back to the H₂S-selective scrubber unit 22. The H₂S, removed from the solvent in the regeneration unit 23, is then passed via stream 26 back to the reaction and separation zones (box 21). For example, referring back to stream 12 of FIG. 1, the stream 26 including the recovered H₂S may be combined with a small make-up stream to form the stream 12 that provides the sulfiding agent to the reaction zone.

Referring back to H₂S-selective scrubber unit 22, the sour recycle gas including CO₂ (having been scrubbed of H₂S) is passed via line 27 to a second scrubber unit 28, namely a CO₂-selective scrubber unit. The CO₂-selective scrubber unit 28 includes a CO₂-selective solvent. Various CO₂-selective solvents are known to those having ordinary skill in the art, and may be included for use in the unit 28. Suitable solvents of this type include, but are not limited to: Dow Ucarsol™ AP-802, AP-804, AP-806, AP-810, AP-814. The CO₂-selective scrubber unit 28 is provided in communication with a CO₂-selective solvent regeneration unit 29. Stream 30 passes rich solvent to the CO₂-selective solvent regeneration unit 29, and stream 31 passes regenerated solvent back to the CO₂-selective scrubber unit 28. The CO₂, removed from the solvent in the regeneration unit 29, is then passed via stream 32 for disposal, such as to an incinerator, for example. The sweet recycle gas remaining after CO₂ scrubbing is the passed from the CO₂-selective scrubber unit 28 back to the reaction and separation zone (box 21) via stream 33. This stream may be about 80% H₂ along with CO, propane, methane, nitrogen, and other light hydrocarbons (shown as line 8 in FIG. 1). Accordingly, the embodiment shown in FIG. 2 provides for the recycle of H₂S in a renewable feedstock hydroprocessing unit that overcomes the problems encountered in the prior art as noted above.

Turning now to FIG. 3, another embodiment of the present disclosure is provided. In this embodiment, a single solvent is used in the recycle gas (and off-gas/LPG scrubbers) of an acid gas removal (AGR) system for H₂S and CO₂ removal, followed by an acid gas enrichment (AGE) system with a solvent highly selective for H₂S and CO₂ separation. Solvents such as Ucarsol™ AP-814 are suitable for CO₂ removal in the AGR system and solvents such as Ucarsol™ HS-103 are suitable for H₂S concentration in the AGE system (both solvents being available from the Dow Chemical Company of Midland, Mich., USA). In embodiments wherein it is desirable to provide a concentrated H₂S stream to a Claus Process system (as known in the art, the Claus Process is provided for recovering elemental sulfur from gaseous hydrogen sulfide), it has been discovered that the Ucarsol™ AGE system solvent is not selective enough to provide an H₂S stream concentrated enough for direct feed to a Claus Process. In prior art systems, two stages of AGE would have been provided for a highly-concentrated H₂S recycle stream. In the present embodiment described in connection with FIG. 3, however, a sterically-hindered amine system, which has superior selectivity, is provided and allows for the recycle of H₂S with a single stage of AGE.

As shown in FIG. 3, box 21 and stream 19 are provided in the same manner as described above with regard to FIGS. 1 and 2, and thus the description thereof need not be repeated herein. In FIG. 3, stream 19 is passed to recycle gas AGR scrubber unit 41. Using a solvent such as the Ucarsol™ AP-814 solvent, the recycle gas AGR scrubber unit 41 removes both H₂S and CO₂ from the recycle gas provided in line 19. Other solvents may also be used in other embodiments, including the Dow Chemical solvents AP-802, AP-804, AP-806, and AP-810. More broadly stated, solvents that are suitable for this application include those that are of the highly-selective amine class, which also more broadly include MEA (monoethanol amine), DEA (diethanolamine), MDEA (methyldiethanolamine), DIPA (diisopropylamine), or DGA (diglycolamine). The recycle gas AGR scrubber unit 41 is provided in communication with a solvent regeneration unit 42. Stream 43 passes rich solvent to the solvent regeneration unit 42, and stream 44 passes regenerated solvent back to the recycle gas AGR scrubber unit 41. The H₂S and CO₂, removed from the solvent in the regeneration unit 42, is then passed via stream 45 for further processing in an AGE unit, as will be described in greater detail below. The sweet recycle gas remaining after H₂S and CO₂ scrubbing is then passed from the recycle gas AGR scrubber unit 41 back to the reaction and separation zone (box 21) via stream 46. This stream may be about 80% H₂ along with CO, propane, methane, nitrogen, and other light hydrocarbons (shown as line 8 in FIG. 1).

As initially noted above, the acid gas stream 45 is passed to AGE separation scrubber regenerator 47 for enhancing and separating the H₂S gas from the CO₂ gas. Using a sterically-hindered amine system, which has superior selectivity, AGE separation scrubber regenerator 47 allows for the recycle of H₂S with a single stage of AGE. A suitable sterically-hindered amine system is described in U.S. Pat. No. 4,618,481 to Heinzelmann et al., the contents of which are herein incorporated by reference in their entirety as if fully set forth herein. The CO₂, separated from the H₂S in the AGE separation scrubber regenerator 47, is then passed via stream 48 for disposal, such as to an incinerator, for example. The H₂S recycle gas remaining after CO₂ separation is then passed from the AGE separation scrubber regenerator 47 back to the reaction and separation zone (box 21) via stream 49. For example, referring back to stream 12 of FIG. 1, the stream 49 including the recovered H₂S may be combined with a small make-up stream to form the stream 12 that provides the sulfiding agent to the reaction zone. Accordingly, the embodiment shown in FIG. 3 provides for the recycle of H₂S in a renewable feedstock hydroprocessing unit that overcomes the problems encountered in the prior art as noted above.

While at least one exemplary embodiment has been presented in the foregoing detailed description of the invention, it should be appreciated that a vast number of variations exist. It should also be appreciated that the exemplary embodiment or exemplary embodiments are only examples, and are not intended to limit the scope, applicability, or configuration of the invention in any way. Rather, the foregoing detailed description will provide those skilled in the art with a convenient road map for implementing an exemplary embodiment of the invention. It being understood that various changes may be made in the function and arrangement of elements described in an exemplary embodiment without departing from the scope of the invention as set forth in the appended claims.

Claims

1. A method for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks comprising the steps of:

combining hydrogen sulfide with hydrogen-rich recycle gas and renewable hydrocarbon feedstocks to form a first stream;

deoxygenating the first stream to form a second hydrocarbon stream comprising deoxygenated hydrocarbons, water, recycle gas, carbon dioxide, and hydrogen sulfide;

separating the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide, and hydrogen sulfide;

selectively scrubbing the hydrogen sulfide from the third recycle stream to form a fourth recycle stream comprising recycle gas and carbon dioxide and a fifth recycle stream comprising hydrogen sulfide; and

selectively scrubbing the carbon dioxide from the fourth recycle stream.

2. The method of claim 1, wherein the hydrogen sulfide comprises a portion of recycled hydrogen sulfide and a portion of make-up hydrogen sulfide.

3. The method of claim 1, wherein the hydrogen-rich recycle gas comprises about 80% by volume of H2.

4. The method of claim 1, further comprising passing the first stream to a guard reactor prior to deoxygenating the first stream.

5. The method of claim 1, wherein deoxygenating the first stream is performed using a sulfided catalyst.

6. The method of claim 1, wherein separating the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream comprises phase separation processes, the third recycle stream comprising a gas phase.

7. The method of claim 1, further comprising isomerizing the deoxygenated hydrocarbons.

8. The method of claim 1, further comprising recycling the fourth recycle stream to form the combined hydrogen-rich recycle gas of the first stream.

9. The method of claim 1, further comprising recycling the fifth recycle stream to form the combined hydrogen sulfide of the first stream.

10. A method for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks comprising the steps of:

combining hydrogen sulfide with hydrogen-rich recycle gas and renewable hydrocarbon feedstocks to form a first stream;

deoxygenating the first stream to form a second hydrocarbon stream comprising deoxygenated hydrocarbons, recycle gas, water, carbon dioxide, and hydrogen sulfide;

separating the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide, and hydrogen sulfide;

selectively scrubbing the hydrogen sulfide and the carbon dioxide from the third recycle stream to form a fourth acid gas stream comprising hydrogen sulfide and carbon dioxide and a fifth recycle gas stream comprising recycle gas; and

separating and enriching the fourth acid gas stream to form a sixth recycle stream comprising hydrogen sulfide.

11. The method of claim 10, wherein the hydrogen sulfide comprises a portion of recycled hydrogen sulfide and a portion of make-up hydrogen sulfide.

12. The method of claim 10, wherein the hydrogen-rich recycle gas comprises about 80% by volume of H2.

13. The method of claim 10, further comprising passing the first stream to a guard reactor prior to deoxygenating the first stream.

14. The method of claim 10, wherein deoxygenating the first stream is performed using a sulfided catalyst.

15. The method of claim 10, wherein separating the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream comprises phase separation processes, the third recycle stream comprising a gas phase.

16. The method of claim 10, further comprising isomerizing the deoxygenated hydrocarbons.

17. The method of claim 10, further comprising recycling the fifth recycle stream to form the combined hydrogen-rich recycle gas of the first stream.

18. The method of claim 10, further comprising recycling the sixth recycle stream to form the combined hydrogen sulfide of the first stream.

19. A system for hydrogen sulfide recycling using selective solvents in the hydroprocessing of renewable feedstocks comprising:

a deoxygenation reactor that deoxygenates a first stream comprising hydrogen sulfide, hydrogen-rich recycle gas, and renewable hydrocarbon feedstocks to form a second hydrocarbon stream comprising deoxygenated hydrocarbons, water, recycle gas, carbon dioxide, and hydrogen sulfide;

a phase separator that separates the carbon dioxide and the hydrogen sulfide from the second hydrocarbon stream to form a third recycle stream comprising recycle gas, carbon dioxide, and hydrogen sulfide;

a first scrubbing unit that selectively scrubs the hydrogen sulfide from the third recycle stream to form a fourth recycle stream comprising recycle gas and carbon dioxide and a fifth recycle stream comprising hydrogen sulfide; and

a second scrubbing unit that selectively scrubs the carbon dioxide from the fourth recycle stream.

20. The system of claim 19, further comprising an isomerization reactor that isomerizes the deoxygenated hydrocarbons.