Patent Application
20240218270
The present disclosure generally relates to the treatment of high chloride (e.g., greater than 3 ppmw chlorine) feedstocks. More specifically, the present disclosure relates to a hydroprocessing system and process that mitigates desublimation of ammonia and hydrogen halides originating from nitrogen- and halogen species present in the high chloride feedstocks.
Hydroprocessing systems are generally used to refine raw feedstocks (e.g., fossil fuels, bio-derived feedstocks, municipal waste-derived feedstocks, solid plastic waste-derived feedstocks, and combinations thereof) into chemicals and fuels. As the desire to develop alternative fuels and carbon circularity increases, hydroprocessing is an attractive technique for converting hydrocarbons from various sources into high quality fuels used as energy sources and chemicals that may be used to create other products. Hydroprocessing includes hydrogenation, hydrodeoxygenation, hydrotreating, hydrocracking, and other reactions that chemically transform, in the presence of a catalyst, hydrocarbons in the feedstock into more desirable hydrocarbons (e.g., chemical and/or fuels).
Certain feedstocks used in hydroprocessing contain contaminants (e.g., metals, nonmetals, halogens, etc.) that may undesirably impact system components (e.g., metallurgy), catalyst performance, and process conditions, reducing system and process efficiency and increase the overall operational cost. Existing techniques used for removing the contaminants, in particular chlorides, include water washing, caustic treating, and solvent extraction. However, such techniques mainly remove water soluble chlorides (e.g., sodium chloride (NaCl), potassium chloride (KCl)) and only a portion of the organic chlorides. Therefore, during hydrotreating, residual chlorides are converted into hydrogen chloride (HCl). Consequently a resultant hydrocarbon effluent stream produced during hydrotreating may still contain an undesirable amount of chlorides in the form of HCl. Not only may the HCl foul system metallurgy (e.g., due to corrosion), but the HCl may react with ammonia produced from nitrogen (N)-containing feed compounds and form ammonium chloride salts in the hydrocarbon effluent stream. These ammonium chloride salts may form undesirable deposits along flow lines of the fluid circuit, which may undesirably impact system metallurgy and the overall hydroprocessing process. Accordingly, there is an existing need to develop processes and systems that remove the HCl formed from the chlorides in hydrocarbon effluent streams in a manner that does not result in corrosion of system metallurgy and deposition of chloride salt.
In an embodiment, a system for hydroprocessing a hydrocarbon feedstock having a first stage including one or more first reactors that may receive the hydrocarbon feedstock and convert the hydrocarbon feedstock into an intermediate product. The feedstock has a total chlorine (Cl) content greater than 3 parts per million weight (ppmw), and the intermediate product includes hydrogen chloride (HCl), ammonia (NH3), and ammonium salt. The system also includes a heating system having a plurality of heat exchangers arranged in a loop and having a heat transfer fluid that may recover and dispense heat to one or more fluids in the first stage. At least one heat exchanger of the plurality of heat exchangers is disposed between the first stage and a separation section, and the at least one heat exchanger may maintain a temperature of the intermediate product above a desublimation temperature of ammonia with hydrogen halide
In another embodiment, a process for hydroprocessing a hydrocarbon feedstock includes feeding a feedstock to a first stage of a hydroprocessing system. The first stage having one or more reactors and that may convert the hydrocarbon feedstock into an intermediate product having hydrogen chloride (HCl), ammonia (NH3), and an ammonium salt, the hydrocarbon feedstock has a total chlorine (Cl) content greater than 3 parts per million weight (ppmw). The process also includes cooling the intermediate product through a first heat exchanger disposed between the first stage and a separation section of the hydroprocessing system to generate a cooled intermediate product. The first heat exchanger includes a heat transfer fluid that may recover heat from the intermediate product, and a temperature of the cooled intermediate product is above a deposition temperature of the ammonium salt
In a further embodiment, a process for hydroprocessing a hydrocarbon feedstock includes cooling a hydrocarbon product having a first temperature through a first heat exchanger disposed between a first stage and a second stage of a hydroprocessing system to generate a cooled hydrocarbon product. The hydrocarbon product is output from a hydrotreater and includes hydrogen chloride (HCl), ammonia (NH3), and an ammonium salt, the first heat exchanger includes a heat transfer fluid that may recover heat from the hydrocarbon product and generate a cooled hydrocarbon product having a second temperature, and the second temperature is less than the first temperature and above a deposition temperature of the ammonium salt.
Additional features and advantages of exemplary implementations of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such exemplary implementations. The features and advantages of such implementations may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims or may be learned by the practice of such exemplary implementations as set forth hereinafter.
Advantages of the disclosure may become apparent upon reading the following detailed description and upon reference to the drawings in which:
One or more specific embodiments of the present disclosure will be described below. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual implementation may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous implementation-specific decisions will be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which may vary from one implementation to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.
When introducing elements of various embodiments of the present disclosure, the articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features.
The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 10% of, within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount.
During hydroprocessing, a feedstock undergoes a primary hydrotreatment to yield primarily liquid product streams having a wide boiling range (e.g., between approximately 20 degrees Celsius (° C.) and 750° C.), as well as gaseous streams. The liquid product streams may include hydrocarbons across a wide boiling point range (encompassing e.g., naphtha, diesel, gasoil, and hydrowax boiling point ranges), which may be further distilled into individual fractions, or processed directly in a steam cracker, hydrocracker, or fluid catalytic cracker (FCC) to produce high-value chemicals, and/or fuels. For example, the hydrotreated feedstock may be used to produce ethylene, propylene, and/or butylene, which are monomers that can be used as building blocks for new plastics. The feedstock may be derived from fossil, biomass, post-consumer products (e.g., solid plastic waste (SPW), municipal solid waste (MSW), etc.)
However, the feedstock also contains impurities that affect the efficiency and efficacy of hydroprocessing. For example, the feedstock contains components such as halogens, metals, and other non-carbonaceous molecules that may cause fouling and corrosion of equipment and/or render catalysts used throughout the process ineffective. In particular, the feedstock may contain contaminants such as chlorides, metalloids such as, for example, silicon (Si) and arsenic (As), and metals, such as, for example, nickel (Ni), vanadium (V), sodium (Na). These contaminants may deactivate/foul catalysts used in hydroprocessing and/or result in undesirable reactions and byproducts, which decrease the efficiency and yield of the process, in addition to fouling downstream equipment. For example, in the case of the chlorides, the chlorides are converted into hydrogen chloride that reacts with ammonia produced from nitrogen (N)-containing feed compounds to form ammonium chloride salts. The ammonium chloride salts may deposit on surfaces of the hydroprocessing system, thereby causing fouling and/or plugging equipment.
There are several techniques for dealing with chlorides and other contaminants present in the feedstock used in hydroprocessing applications. One technique for decreasing the level of contaminants in these feedstocks is to blend a portion of the feedstock with naphtha or hydrowax sourced from conventional virgin crude oil refining. This mixture is co-processed in a cracker unit to generate smaller molecules used to form new chemicals. The amount of feedstock in the mixture is such that the contamination level in the mixture is within the contamination level requirements of the cracker unit. However, while this technique achieves the contamination level requirements for the cracker, this technique merely dilutes the feedstock with the naphtha/hydrowax. As such, only a small amount of the feedstock may be processed in the cracker unit at a given time. However, as the demand for alternative fuels and carbon circularity increases, the volumes of diluent sourced from conventional virgin crude oil may need to increase in proportion to meet the contamination level limits of the cracker, rendering this technique inefficient and economically unattractive in light of reducing demands for crude oil based products.
Other techniques include injecting an amine upstream of a hydrotreater to convert the inorganic chloride components to ammonium chloride salts, which may be removed through a water washing step. However, this technique only effectively addresses inorganic chlorides, which account for a relatively small percentage (e.g., less than approximately 10%) of the total chlorides found in some the feedstock. In a hydrotreater, even organic feed chlorides are transformed into hydrogen chloride (HCl). Ammonia (NH3) may also be formed in the hydroprocessing system (e.g., in a hydrotreater) from a chemical reaction of the nitrogen compounds present in the raw feed with hydrogen. Under certain system conditions (e.g., temperature and partial vapor pressures of HCl and NH3), ammonia and hydrogen chloride may desublimate from the vapor phase and deposit as solid ammonium chloride (NH4Cl) on system components (e.g., fluid flow circuit, inlets, etc.). For example, as a hydrotreater effluent stream is cooled from the temperature required in the hydrotreater down to low temperatures that are close to ambient temperatures (e.g., 50° C.), NH4Cl salts may form and deposit in the system circuit causing fouling and plugging.
As should be noted, for a given mass action value the sublimation temperature (ST) of NH4Cl exceeds the ST of NH4F and is considerably higher than the ST of ammonium sulfide (NH4HS). If the chlorine content of a feed exceeds 3 ppmw then, generally, the ST of NH4Cl becomes the highest and governing ST of all the ST's of the ammonium salts. Hence if desublimation of ammonia and hydrogen chloride is prevented for more than 3 ppmw Cl in the feed, deposition of other ammonium salts like NH4F and NH4HS is generally also avoided.
Accordingly, disclosed herein is a system and method that includes a heating system having a plurality of heat exchangers arranged in a loop that dispenses and recovers heat in the system for hydroprocessing of high chloride feedstocks (e.g., feedstocks having greater than or equal to 3 ppmw Cl) in a manner that mitigates deposition of ammonium chloride salts on the hydroprocessing equipment. As discussed in further detail below, the disclosed heating system controls a temperature of a hydrotreater effluent stream such that, when the hydrotreater effluent stream is cooled, its temperature remains above the deposition temperature of ammonium chloride. In addition, the disclosed heating system avoids formation of cold spots along the fluid circuit that would exist when using traditional feed/effluent heat exchange schemes and that are below the deposition temperature of ammonium chloride. By using the disclosed system and method, the total chlorides in the hydrotreater effluent stream may be dissolved in wash water without deposition of chloride salts on the hydroprocessing system. Moreover, heat inputted and generated during hydroprocessing may be recovered and transferred to other hydroprocessing steps, thereby improving the energy efficiency of hydroprocessing high chloride feedstock.
With the foregoing in mind,
The system 100 includes a hydro-pretreating stage 116 and a hydrocracking stage 118, each stage 116, 118 having various components that treat liquid and/or gaseous streams to generate high-value products (e.g., fuels, chemicals, etc.) in the system 100. However, as should be appreciated, in certain embodiments, the system 100 may only have a single stage (e.g., the hydro-pretreating stage 116). In certain embodiments, the system 100 may include a pretreatment section upstream of the hydro-pretreating stage 116. The pretreatment section may remove certain undesirable components from a feed used in the system 100. However, this removal may only be partial. In the illustrated embodiment, the hydro-pretreating stage 116 includes a hydro-pretreating system 120 having a series of reactors that remove certain contaminants, to various extents, from and convert a feedstock 124 into an intermediate product 126. For example, the hydro-pretreating system 120 includes a di-olefin saturation reactor 130, a demetallization reactor 132, and a hydrotreater 138. The hydro-pretreating system 120 also includes a first heat exchanger 140 (e.g., an indirect heat exchanger) that pre-heats a di-olefin saturation reactor effluent 142 using heat recovered from the system 100, as discussed in further detail below. The reactors 130, 132, and hydrotreater 138 may be in a single reactor or separate reactors, positioned in series and/or in parallel.
The feedstock 124 may be any high chloride feedstock (e.g., a feedstock having greater than 3 parts per million weight (ppmw) Cl) derived from SPW, fossil, biomass, and combinations thereof. In embodiments in which the feedstock 124 is derived from SPW, the SPW undergoes a primary conversion step such as, but not limited to, pyrolysis, hydropyrolysis, hydrothermal liquefaction, or hydrogenolysis to generate a liquid stream. The feedstock 124 generated from SPW may be a mixture of polymer fragments/oligomers (e.g., depolymerized polymers) and contaminants. In addition to the high level of chlorides (e.g., greater than 3 ppmw Cl), the feedstock 124 may have other contaminants such as, but not limited to, bromine (Br), fluorine (F), potassium (K), sodium (Na), phosphorus (P), and silicon (Si). Other contaminants include alkali metals (e.g., lithium (Li), alkali-earth metals (e.g., calcium (Ca) and magnesium (Mg)), transition metals (e.g., nickel (Ni), vanadium (V), zinc (Zn), and iron (Fe)) and nonmetals such as sulfur (S), nitrogen (N), and oxygen (O) that undesirably impact catalyst activity, process efficiency, and equipment metallurgy. Therefore, these contaminants are removed or reduced from the feedstock 124 during hydroprocessing (e.g., in a pretreatment section and/or reactor 132). The feedstock 124 also includes other components, such as di-olefins, that may also need to be removed/reduced (e.g., converted into olefins and paraffins) during hydroprocessing.
While in the hydro-pretreating system 120, the feedstock 124 undergoes di-olefin saturation, demetallization and/or desilication, deoxygenation, desulfurization, denitrogenation and/or dechlorination. For example, in operation, the di-olefin saturation reactor 130 receives the feedstock 124 where it undergoes selective hydrogenation in the presence of a hydrogenation catalyst and hydrogen (H2). The selective hydrogenation catalyst may be any suitable hydrogenation catalyst such as Ni-based hydrogenation catalysts. By way of non-limiting example, the Ni-based hydrogenation catalysts may be a NiMo catalyst supported on alumina. The selective hydrogenation converts the di-olefins (i.e. hydrocarbons having two conjugated double bonds) in the feedstock 124 into less complex olefins (i.e. hydrocarbons having a single double bond). To avoid complete hydrogenation of these olefins, and olefins already present in the feedstock 124, to form paraffins and the resulting undesirable temperature rise in the reactor, the di-olefin saturation reactor 130 is maintained at an operating temperature range of between approximately 100° C. and approximately 200° C.
Following di-olefin hydrogenation in the di-olefin saturation reactor 130, the resultant effluent stream 142 is fed to the demetallization reactor 132 for removal of contaminants such as alkali metals (e.g., Li, Na, and K), alkali-earth metals (e.g., Mg and Ca), transition metals (e.g., Ni, V, Zn, and Fe), and non-metals (e.g., P, As and Si). Prior to feeding the effluent stream 142 to the demetallization reactor 132, the stream 142 is preheated in the heat exchanger 140. As discussed above, the temperature of the di-olefin saturation reactor 130 is maintained at a range of between approximately 100° C. and 200° C. to avoid complete hydrogenation of any olefins into paraffins. However, for demetallization of the effluent stream 142, it is desirable for the effluent stream 142 to be at a temperature above 300° C. Therefore, the effluent stream 142 is heated in the first heat exchanger 140 to a temperature in the range of between approximately 300° C. to approximately 375° C. depending on reactor conditions (e.g., start of run conditions or end of run conditions), thereby generating a preheated effluent stream 146.
The first heat exchanger 140 forms part of a heating system 148 of the system 100. As discussed in further detail below, the heating system 148 includes a plurality of heat exchangers (such as the first heat exchanger 140) arranged in a loop that circulates a heat transfer fluid (HTF) 144 that dispenses and recovers heat from various steps in the hydroprocessing process disclosed herein. The heat exchangers of the heating system 148 disclosed herein are indirect heat exchangers that utilize the HTF 144 to recover heat from certain effluent streams produced in the system 10 and dispense the recovered heat to other effluent streams generated in the system 100.
The demetallization reactor 132 may have one or more reactors each equipped with one or more guard beds that remove metal contaminants (e.g., Li, Na, K, Mg, Ca, Ni, V, Fe and Zn) and nonmetals (e.g., P, As and Si) from the preheated effluent stream 146 in the presence of a demetallization catalyst and hydrogen. The demetallization catalyst may be any suitable catalyst that removes metals and non-metals such as, but not limited to, Ni, V, Na, P, Si, and arsenic (As) from the preheated effluent stream 146. By way of non-limiting example, the demetallization catalyst may be a nickel-based catalyst such as nickel molybdenum (NiMo) with or without phosphorus (NiMoP) or a combination. The NiMo/NiMoP catalyst(s) hydrometallize(s) the metal-containing molecules and trap and remove the metals from the preheated effluent stream 146 and generate(s) a demetallized effluent stream 150. By removing the contaminating metals from the preheated effluent stream 146, the activity of downstream catalysts used in the system 100 may not be undesirably impacted. For example, certain hydrotreating and/or hydrocracking catalysts may be sensitive to the metal contaminants. These metal contaminants may decrease the activity of hydrotreating and/or hydrocracking catalysts used in the system 100 due, in part, to poisoning of the catalyst. The poisoned catalysts will need to either be removed or regenerated, resulting in a decrease in system efficiency and adding complexity to the process. However, by treating the preheated effluent stream 146 in the demetallization reactor 132, the undesirable impact of the metal contaminants throughout the process may be mitigated. As should be appreciated, the demetallization catalyst(s) in reactor 132 may convert chlorides from the preheated effluent stream 146, into hydrogen chloride.
Over time, the metal uptake capacity of the demetallization catalyst decreases. Therefore, the demetallization catalyst may need to be replaced with fresh or regenerated catalyst. Accordingly, in certain embodiments, the demetallization reactor 132 may include a set of reactors arranged in parallel such that one reactor remains on stand-by for when the demetallization catalyst of the other reactor needs to be replaced or regenerated. For example, when the metal uptake capacity of the catalyst in the operating reactor is below a desired level, this reactor may be taken offline and the stand-by reactor having fresh or regenerated catalyst is placed online. As such, system and process downtime is minimized.
Downstream of the demetallization reactor 132 is the hydrotreater 138. The hydrotreater 138 receives the demetallized effluent stream 150 and converts it into an upgraded liquid having a quality suitable for cracking, for example, in a steam cracker or hydrocracker. For example, the hydrotreater 138 receives the demetallized effluent stream 150 where it undergoes hydrotreatment in one or more hydrotreating reactors in the presence of one or more hydrotreating catalysts and hydrogen 152 at a pressure of between approximately 30 barg and approximately 150 barg and a temperature in a range of from approximately 100° C. to 500° C. The hydrotreater 138 removes heteroatoms (e.g., sulfur (S), nitrogen (N), and oxygen (O)) and saturates olefins and aromatics via a series of hydrotreating reactions with the hydrogen 152. In the illustrated embodiment, the hydrogen 152 is provided by a hydrogen manufacturing unit (HMU) 154. By way of non-limiting example, the HMU 154 may be a steam methane reformer or any other suitable HMU, or an electrolyzer. In certain embodiments, part of the hydrogen 152 may be recovered from the system 100. For example, as shown in the illustrated embodiment, a separation system 156 outputs a hydrogen-rich off gas 159 which may be recycled back to the HMU 154 for recovery of the hydrogen.
In addition to removing the heteroatoms from the demetallized effluent stream 150, the hydrotreating catalyst facilitates saturation of the olefins and at least a portion of aromatics present in the stream 150, thereby generating the intermediate product 126. The hydrotreating catalyst system used in the hydrotreater 138 may be any suitable hydrotreating catalyst or combinations of hydrotreating catalysts having a desired activity in the temperature range of the disclosed hydrotreatment process. For example, the hydrotreating catalyst is selected from sulfided catalysts having one or more metals from the group consisting of Ni, Co, Mo, or W supported on a metal oxide. Suitable metal combinations include sulfided NiMo, sulfided CoMo, sulfided NiW, sulfided CoW and sulfided ternary metal systems having any three metals consisting of Ni, Co, Mo, W, and noble metals. Catalysts such as sulfided Mo, sulfided Ni and sulfided W are also suitable for use. The oxide supports for the sulfided metal catalysts include, but are not limited to, alumina, silica, titania, ceria, zirconia, as well as binary oxides such as silica-alumina, silica-titania and ceria-zirconia, and combinations thereof. Preferred supports include alumina, silica, and titania. The support may optionally contain regenerated and revitalized fines of spent hydrotreating catalysts (e.g., fines of CoMo on oxidic supports, NiMo on oxidic supports and fines of hydrocracking catalysts containing NiW on a mixture of oxidic carriers and zeolites). Total metal loadings on the catalyst are in the range of from approximately 5 wt % to approximately 35 wt % (expressed as a weight percentage of calcined catalyst in oxidic form, e.g., weight percentage of nickel (as NiO) and molybdenum (as MoO3) on calcined oxidized NiMo on alumina catalyst). Additional elements such as phosphorous (P) may be incorporated into the catalyst to improve the dispersion of the metal. Metals can be introduced on the support by impregnation or co-mulling or a combination of both techniques.
The catalyst in the hydrotreater 138 removes S, N, and 0 from the stream 150 by way of converting these heteroatoms to hydrogen sulfide (H2S), ammonia (NH3), and water (H2O), respectively. Stream 150 also contains (residual) chlorides. These chlorides in stream 150 are converted to hydrogen chloride (HCl) in the hydrotreater 138. As discussed in further detail HCl may form undesirable salts that may deposit on system surfaces resulting in undesirable pressure drops and corrosion of system metallurgy.
Reactions occurring in the hydrotreater 138 are exothermic and, thereby, increase the temperature of the intermediate product 126 to above 300° C. However, such temperatures are not suitable for downstream processes. Therefore, the temperature of the intermediate product 126 needs to be decreased to below 250° C. upstream of the separation system 156. While a quench fluid (e.g., H2 gas) may be fed to the hydrotreater 138 to control its operating temperature and hence the temperature of the intermediate product 126, the temperature of the latter may still be above 250° C., which is not suitable for the separation system 156. Due, in part, to the concentration of HCl and NH3 in the intermediate product 126, decreasing the temperature below 250° C. may result in deposition of undesirable chloride salts on system metallurgy. For example, in the presence of H2, the HCl and NH3 form solid ammonium salts (e.g., ammonium chloride (NH4Cl)). Under certain system conditions (i.e. temperatures below approximately 250° C. and a product of partial vapor pressures of HCl and NH3 in excess of 10,000,000 Pa2), the ammonia and hydrogen chloride may desublimate from the vapor phase and form solid deposits on system components (e.g., effluent lines, heat exchangers, reactors, etc.). The deposition of ammonium chloride on system components results in fouling of equipment and undesirable pressure drops. For example, the deposited ammonium chloride may foul heat exchangers, resulting in inefficient heat transfer. Heat exchanger tubing and effluent lines may become plugged by the deposited ammonium chloride salt, which further decreases heat transfer and causes undesirable pressure drops putting additional stress on equipment to overcome the pressure drops. In addition, ammonium chloride salt is hygroscopic and attracts water present in the intermediate product 126. This results in wetting of the ammonium chloride salt and results in corrosion of equipment. Moreover, the high level of total chlorides (e.g., greater than 3 ppmw Cl) in certain feedstocks used in hydroprocessing and the partial vapor pressures of the HCl and NH3 in the intermediate product 126 are such that the temperature at which desublimation occurs may be at a level that heat recovery directly into a cold reactor feed is not possible, especially when cold spots are present throughout heat exchanger tubing, effluent lines, and other system components. Ammonium chloride may deposit in cold spot areas along the effluent flow causing fouling of equipment components and undesirable pressure drops.
To mitigate the presence of cold spots and deposition of ammonium chloride on system components, the system 100 disclosed herein includes a second heat exchanger 158 positioned downstream of the hydrotreater 138 and upstream of the hydrocracking stage 118. The second heat exchanger 158 forms part of the plurality of heat exchangers of the heating system 148. The second heat exchanger 158 recovers heat from the intermediate product 126 using the HTF 144 provided from the heating system 148 to generate a cooled intermediate product 160. The HTF 144 absorbs heat from the intermediate product 126, thereby cooling and decreasing the overall temperature to below 300° C. but above the desublimation temperature of the ammonia and hydrogen chloride present in the intermediate product 126. For example, the HTF 144 cools the intermediate product 126 to a temperature between approximately 250° C. and 285° C. Unlike certain existing systems that use direct heat exchange with cooled feedstock as a heat sink, the system disclosed herein uses the HTF 144, which not only cools the intermediate product 126, but also mitigates the presence of cold spots and/or low heat sink temperatures that may cause localized deposition of ammonium chloride. The HTF 144 temperature at the inlet of the second heat exchanger 158 is controlled such that it is above the deposition temperature of the ammonium salt. The HTF 144 circulating through the loop of the heating system 148 is heated using heat recovered from a process of the system 100 to a temperature above the deposition temperature of ammonium salt prior to passing through the second heat exchanger 158. In this way, ammonium chloride salt does not deposit anywhere in the heat exchanger 158, which may plug the exchanger, lower the exchanger outlet pressure, and foul system components. By incorporating the second heat exchanger 158 downstream of the hydrotreater 138, the system 100 may be able to process high chloride feedstocks (e.g., feedstocks having greater than 3 ppmw Cl) without having to remove the chlorides upstream of the hydrotreater 138.
The second heat exchanger 158 recovers heat from the intermediate product 126 to generate the cooled intermediate product 160. The maximum amount of heat that may be recovered is limited as the intermediate product 126 must not be cooled to temperatures below the deposition temperature of ammonium salts (e.g., ammonium chloride) that may form in the intermediate product 126. The resulting temperature of the intermediate product 126 is still not sufficiently low to allow further processing in the separation system 156. For example, the maximum amount of heat recovered by the HTF 144 in the second heat exchanger 158 may be between approximately 25% to 85% of the total heat input into the liquid feed (e.g., the intermediate product 126), the higher end of this range being achievable with lower desublimation temperatures (e.g., low feed chlorine- and/or nitrogen contents in the intermediate product 126). However, for the cooled intermediate product 160 to undergo further processing downstream of the second heat exchanger 158, the cooled intermediate product 160 needs to be cooled to a temperature that is significantly below the deposition temperature of ammonium chloride (e.g., to a temperature in the range of 25-75° C.). Therefore, to mitigate deposition of the ammonium chloride downstream of the second heat exchanger 158, while also decreasing the temperature of the cooled intermediate product 160 to a temperature that is suitable for further processing in the separation system 156, the cooled intermediate product 160 is diluted and quenched using recycled wash water and a hydrocarbon stream, thereby generating a diluted intermediate product 162.
For example, a wash water stream 164 generated in the separation system 156 is injected into the cooled intermediate product 160 upstream of the separation system 156. The wash water stream 164 dissolves and dilutes the HCl and NH3 in the cooled intermediate product 160 such that the concentration of these components in the vapor phase is at a level where desublimation of these components does not occur at the lower temperatures (e.g., temperatures below 75° C.). The cooled intermediate product 160, however, is still at a temperature above 250° C. Therefore, a portion of the wash water stream 164 injected into the stream of the cooled intermediate product 160 may vaporize. For example, approximately 45% to 90% of the injected wash water stream 164 may be vaporized when it comes in contact with the cooled intermediate product 160. To maintain at least approximately 25% to 80% of the injected wash water stream 164 in the liquid phase, the wash water stream 164 may be mixed with a hydrocarbon stream 170 generated in the separation system 156. In addition, by adding a portion of the hydrocarbon stream 170 to the cooled intermediate product 160, the amount of the wash water stream 164 required to maintain at least approximately 25% to 80% of the injected wash water stream 164 in the liquid phase is decreased. While in the illustrated embodiment the streams 164 and 170 are each separately injected into the cooled intermediate product 160 (simultaneously or in series), in other embodiments the streams 170 is mixed with the wash water stream 164 before injecting into the cooled intermediate product 160. In embodiments in which the streams 164 and 170 are separately injected, the hydrocarbon stream 170 may be added first to quench the cooled intermediate stream 160, followed by injection of the wash water stream 164 to dilute the cooled intermediate product 160 and maintain the ammonium chloride and other salts in solution.
The wash water stream 164 may include recycled water from the separation system 158, fresh make-up water from a make-up water tank, or both. The amount of the wash water stream 164 injected into the cooled intermediate product 160 depends on the concentration of chlorides (e.g., HCl) and ammonia (NH3) in the cooled intermediate product 160, nitrogen content of the feedstock 124, and pH of the wash water stream 164. In certain embodiments, if the pH of the recycled wash water stream 164 is below a desired pH (e.g., an acidic pH), ammoniated fresh water may be injected into the wash water stream 164 to maintain the pH within a desired range of between 6 and 7. The hydrocarbon stream 170 may be a condensed and separated hydrocarbon liquid generated in the separation system 156.
The resultant diluted and water-washed intermediate product 162 is fed to the separation system 156 where the product 162 is separated into four product streams: an aqueous phase (e.g., the recycled was water stream 164), a hydrocarbon liquid product 174, a hydrogen (H2)-rich off-gas 159, and recycle gas 176. The aqueous phase is used as the wash water stream 164. In certain embodiments, a portion of the aqueous phase is routed to a wash water recovery system external to the system 10 as a bleed stream. In certain embodiments, the diluted intermediate product 162 may be cooled in a cooler (e.g., an air cooler) prior to being fed to the separation system 156. The cooler may further cool diluted intermediate product 162 to a temperature below 75° C. As the HCl and NH3 in the cooled diluted intermediate product 162 are dissolved and diluted in the aqueous phase, desublimation of ammonia with hydrogen chloride or with other hydrogen halides to form ammonium salts is not of concern. Moreover, in the separation system 156, the aqueous phase (including the HCl and NH3) are separated and removed from the hydrocarbon liquid product 174 upstream of the hydrocracking stage 118. As such, processes in the hydrocracking stage 118 are no longer undesirably impacted by the chlorides present in the feedstock 124. Therefore, unlike certain existing hydroprocessing systems, the system 100 may be used for hydroprocessing of high chloride feedstocks, such as the feedstock 124.
The separation system 156 includes one or more separators (e.g., cold high pressure, cold low pressure separators, hot high pressure separators, and hot low pressure separators) that separate the diluted intermediate product 162 into the wash water stream 164, the hydrocarbon liquid product 174, and the hydrogen (H2)-rich off-gas 159 and the recycle gas 176. In certain embodiments, the diluted intermediate product 162 may be combined with another hydrocarbon stream generated in the system 100 (e.g., a hydrocarbon stream generated in a downstream conversion unit such as a steam cracker or hydrocracker). The recycle gas 176 may be contacted with make-up wash water (e.g., a portion of the stream 164 and/or from a make-up wash water drum) in the separation system 156 to scrub off, or otherwise remove, NH3 from the recycle gas 176 before it is routed to a recycle gas compressor and utilized within processes of the system 100.
The hydrocarbon liquid product 174 output from the separation system 156 is fed to a product recovery section 182. In the product recovery section 182, the hydrocarbon liquid product 174 may undergo distillation to separate it into fractions according to ranges of the boiling points of the hydrocarbons contained in the hydrocarbon liquid product 174. For example, the hydrocarbon liquid product 174 includes naphtha range hydrocarbons 194 and hydrowax 200 among others. The naphtha range hydrocarbons 194 may be fed to a naphtha steam cracker or fluid catalytic cracker, for example, where they are converted into lower olefins used in the manufacturing of new consumer plastic goods. The remaining fractions (e.g., the hydrowax 200) may also be used in a chemical production step as feed to a heavy oil steam cracker, or in other processes to generate commercially viable products such as fuels and other chemicals. In certain embodiments, the hydrowax 200 may be recycled to a hydrocracking reactor 202 in the hydrocracking stage 118. The hydrocracker 202 converts the hydrowax 200 into additional naphtha range hydrocarbons. Optionally, in certain embodiments, the naphtha or heavier cuts, may be recycled to the hydrotreating reactor 138 or other reactors (e.g., a pretreating reactor) in the system 100. The product recovery section 182 may also generate light gases 188 (e.g., C1 to C4, NH3, H2S, H2O (e.g., water vapor), CO, and CO2) as byproducts.
As discussed above, the hydrowax 200 may be fed to the hydrocracking reactor 102 for further processing. The hydrocracking reactor 202 breaks down (i.e., cracks) the hydrocarbons in the hydrowax 200 in the presence of a hydrocracking catalyst and the hydrogen 152 to form a hydrocracked (HC) intermediate product 204 having increased portion of lighter hydrocarbons (e.g., C5-C9 hydrocarbons in the naphtha range) that are substantially free of oxygen, nitrogen, sulfur, metals, and halogens, and gases such as H2, CO, and CO2 among others. The hydrocracking reactor 202 operates at a pressure of between approximately 50 barg to approximately 200 barg, and at a temperature in a range of from approximately 275° C. to 500° C. In certain embodiments, the temperature and pressure in the hydrocracking reactor 202 are substantially the same as in the hydrotreating reactor 138. Prior to entering the hydrocracking reactor 202, the hydrowax 200 is heated by a third heat exchanger 206 of the heating system 148. For example, the hydrowax 200, available from the product recovery section 182 at a temperature in the range of approximately 180-210° C., may be heated to a temperature of in the range of approximately 325° C. and 360° C. by the HTF 144.
The hydrocracking catalyst used in the hydrocracking reactor 202 includes any suitable hydrocracking catalyst having a desired activity in the temperature range of the disclosed hydrocracking process. For example, the hydrocracking catalyst is selected from sulfided catalysts having one or more metals from the group consisting of Ni, Co, Mo, or W supported on a metal oxide. Suitable metal combinations include sulfided NiMo, sulfided CoMo, sulfided NiW, sulfided CoW and sulfided ternary metal systems having any three metals from the family consisting of Ni, Co, Mo, and W. Catalysts such as noble metal zeolites, sulfided Mo, sulfided Ni and sulfided W are also suitable for use. The metal oxide supports for the sulfided metal catalysts include, but are not limited to, alumina, silica, titania, ceria, zirconia, as well as binary oxides of alumina and silica being either amorphous or having defined structure such as zeolite Beta, X, or Y, silica-titania, and ceria-zirconia. Preferred supports include alumina, silica, and titania. The support may optionally contain regenerated and revitalized fines of spent hydrotreating catalysts (e.g., fines of CoMo on oxidic supports, NiMo on oxidic supports and fines of hydrocracking catalysts containing NiW on a mixture of oxidic carriers and zeolites). Total metal loadings on the catalyst are in the range of from approximately 5 wt % to approximately 35 wt % (expressed as a weight percentage of calcined catalyst in oxidic form, e.g., weight percentage of nickel (as NiO) and molybdenum (as MoO3) on calcined oxidized NiMo on alumina catalyst). Additional elements such as phosphorous (P) may be incorporated into the catalyst to improve the dispersion of the metal. Metals can be introduced on the support by impregnation or co-mulling or a combination of both techniques.
In certain embodiments, a portion of the hydrocracked intermediate product 204 is fed to the separation system 156 where it undergoes a first hot separation process in a gas-liquid separator that separates and removes the vapor phase (e.g., H2, C1 to C4, and higher boiling hydrocarbons) from the hydrocarbon liquid in the hydrocracked product 204 in either a single or multiple steps. Any suitable phase separation technique may be used to separate and remove the vapor from the hydrocarbon liquid. The vapor phase thus obtained may be combined with the cooled intermediate product 160 from the hydro-pretreatment system 120, for further condensing, cooling and phase separation in separation system 156 to generate the hydrocarbon liquid product 174.
In certain embodiments, the recycle gas 176 is fed to a gas clean-up system that removes H2S, NH3, CO2, and, in certain embodiments, CO, and trace amounts of organic sulfur-containing compounds, if present, as by-products of the process, thereby generating a hydrogen-rich stream that may be recycled to the hydro-pretreatment system 120 and/or the hydrocracking reactor 202. The liquid hydrocarbon stream separated from the hydrocracked product 204 forms part of the hydrocarbon liquid product 174 sent to the product recovery section 182.
The system 100 may also include a controller 206 to govern operation of the system 100. The controller 206 may independently control operation of the system 100 by electrically communicating with sensors, control valves, pumps, and other flow adjusting features throughout the system 100. The controller 206 may include a distributed control system (DCS) or any computer-based workstation that is fully or partially automated. For example, the controller 206 may be any device employing a general purpose or application-specific processor 208, both of which may include memory circuitry 210 for storing instructions such as system parameters (e.g., pretreating conditions, hydrotreatment conditions, hydrocracker conditions, heating system conditions, contaminant concentrations, desublimation temperatures, pH, etc.). The processor 208 may include one or more processing devices, and the memory circuitry 210 may include one or more tangible, non-transitory, machine-readable media collectively storing instructions executable by the processor 208 to control actions described herein.
In one embodiment, the controller 206 may operate control devices (e.g., valves, pumps, etc.) to control amounts and/or flows between the different system components. It should be noted that there may be valves throughout the system 100 used to adjust different amounts and/or flows between system components. For example, the controller 206 may also govern operation of valves to control an amount or adjust a flow of the feedstock 124, the intermediate products 126, 160, 162, the streams 164, 170, 172, the hydrocarbon liquid product 174, the hydrocracked intermediate product 204, and hydrogen 152 that are fed to the different components of the system 100. In certain embodiments, the controller 206 may use information provided via input signals to execute instructions or code contained on a machine-readable or computer-readable storage medium (e.g., the memory circuitry 210) and generate one or more output signals 214 to the various control devices (e.g., valves, pumps, etc.) to control a flow of fluids (e.g., the feedstock 124, the intermediate product 126, 160, 162, the streams 164, 170, the hydrocarbon liquid product 174, the hydrocracked intermediate product 204, and hydrogen 152 or other suitable fluids) throughout the system 100.
As discussed above, the heating system 148 includes a plurality of heat exchangers (e.g., the heat exchangers 140, 158, 206) that recover and transfer heat generated in the system 10. The heat exchangers 140, 158, 206 of the heating system 148 are indirect heat exchangers that utilize the HTF 144 to recover and transfer the heat generated in the system 100 to various streams and system components. For example,
In the embodiment illustrated in
Downstream of the heater 234, the heated transfer fluid 238 may be split into various streams that each go through a respective heat exchanger 140, 206, 242, 246 positioned throughout the system 100. For example, a portion of the heated transfer fluid 238 is directed to the first heat exchanger 140. The first heat exchanger 140 heats an effluent (e.g., the di-olefin saturation effluent stream 142) in a first stage (e.g., the hydro-pretreating stage 116) of a hydroprocessing system (e.g., the system 100). Another portion of the heated transfer fluid 238 may be directed to the third heat exchanger 206 in a second stage (e.g., the hydrocracking stage 118) of the hydroprocessing system (e.g., the system 100) to heat a hydrocarbon product (e.g., the hydrowax 200) generated in a product recovery system (e.g., the product recovery system 182). Additional portions of the heated transfer fluid 238 may be fed to heat exchangers 242, 246 disposed within the hydroprocessing system (e.g., the system 100). For example, the heat exchangers 242, 246 may be within the product recovery section 182. These heat exchangers 242, 246 may heat various streams generated in the product recovery section 182. For example, the product recovery section 182 may include one or more distillation columns (e.g., stabilizer and splitter) that separate light hydrocarbons (e.g., C4 and lighter) from heavier hydrocarbons (e.g., C4+) in a liquid stream (e.g., the hydrocarbon liquid product 174). The heated heat transfer fluid 238 circulating through the heat exchangers 242, 246 provide heat (i.e., transfer heat) to a reboiling liquid that is recycled back into the distillation column.
After the heated transfer fluid 238 transfers heat to fluids passing through the heat exchangers 140, 206, 242, 246, thereby heating process fluids, each respective heat exchanger 140, 206, 242, 246 outputs a cooled heat transfer fluid 250, 250′. The cooled heat transfer fluid 250, 250′ may be at a temperature in the range of between approximately 200° C. and 275° C. The cooled heat transfer fluid 250 is directed to the second heat exchanger 158. For example, as discussed above with reference to
The cooled heat transfer fluid 250′ is returned to the fluid vessel 230 and recycled throughout the heating system 148. In certain embodiments, a portion of the first heated transfer fluid 238 may bypass the heat exchangers 140, 206, 242, 246 and be mixed with the cooled transfer fluid 250′ upstream of the fluid vessel 230, thereby generating a third heated transfer fluid 256. This may help to maintain the heat transfer fluid 232 in the fluid vessel 230 at a desired temperature (e.g., a temperature in the range of between 350° C. and 380° C.). The heating system 148 may also include a cooler 260 (e.g., an air cooler). The cooler 260 may receive the heat transfer fluid 232 from the fluid vessel 230, cool to a desired temperature to generate a cooled fluid 262. Depending on the temperature of the transfer fluid 250, the cooled fluid 262 may be injected into the stream of the transfer fluid 250 to adjust (lower) the temperature. For example, if a temperature of the cooled heat transfer fluid 250 is above a desired temperature to allow maximum heat recovery from the intermediate product (e.g., the intermediate product 126), the heating system 148 may add the cooled fluid 262 to the cooled heat transfer fluid 250 to decrease the temperature of the cooled heat transfer fluid 250 to the desired temperature.
The optimum temperature for the cooled heat transfer fluid 250 going to the second heat exchanger 158 is a trade-off between maintaining a safe margin over and above the estimated desublimation temperature in the intermediate product 126 (i.e. driving a higher HTF supply temperature to the second heat exchanger 158), and maximizing the temperature difference between the intermediate product 126 and HTF supply to the second heat exchanger 158, for maximum heat recovery (driving lower HTF supply temperatures). The cooler 260, which is included to enable starting up the heating system 148 without any demand yet for heat in hydroprocessing system 10, allows to establish this optimum temperature to heat exchanger 158.
The heating system 148 may also include a make-up drum 268. The make-up drum 268 may be used to store the HTF 232 not in circulation throughout the heating system 148. If a fluid level of the HTF 232 within the fluid vessel 230 drops below a desirable level (e.g., the heating system 148 liquid inventory contracts with lower temperatures), the make-up drum 268 may feed HTF 232 to the fluid vessel 230 to increase the fluid level. Conversely, if the fluid level of the HTF 232 within the fluid vessel 230 rises above a desired level (thermal expansion of the liquid inventory with higher temperature), excess HTF 232 may be bled to the make-up drum 268.
The heating system 148 includes valves to control flow of the fluids 232, 238,250, 250′, 254, 256, 262 throughout the various heat exchangers and other components of the heating system 148. In addition, the heating system 148 includes pressure and temperature sensors throughout to control the pressure and temperature of the fluids 232, 238,250, 250′, 252, 254, 256, 262, respectively, within the heating system 148. The valves and sensors of the heating system 148 are controlled by a controller (e.g., the controller 206).
In another embodiment of the heating system 148, generation of steam from imported boiler feed water (BFW) is used to recover heat from the intermediate product 126. By manipulating the saturation pressure of the steam generated, the lowest temperature to which the intermediate product 126 is exposed in the second heat exchanger 158 can be accurately controlled. This avoids the formation of cold spots in the system flow circuit between the hydro-pretreatment system 120 and the separation system 156, effectively mitigating the deposition of ammonium chloride (NH4Cl) and other salts in this system. Preheating the BFW can be done by condensing imported utility steam having a higher saturation pressure. Heat contained in the steam generated in the second heat exchanger 158, supplemented with some additional imported utility steam, can favorably be dispensed to, for example, the diolefin saturation effluent stream 142 in heat exchanger 140, and/or to suitable consumers of heat (in e.g. the product recovery section 182).
In the heat recovery step 292, the heat exchanger (e.g., the heat exchanger 158) cools the intermediate product by using the heat transfer fluid to recover a maximum amount of heat from the intermediate product while still maintaining the temperature of the resultant cooled intermediate product (e.g., the cooled intermediate product 160) above the deposition temperature of the ammonium salts. The heated heat transfer fluid (e.g., the 2nd heated transfer fluid 254) having the recovered heat from the intermediate product may be fed back to the heating system and used to transfer heat to other fluids or system components throughout the hydroprocessing system. In addition to recovering heat from the intermediate product, the heat transfer fluid avoids the formation of cold spots in the fluid circuit by heating the heat exchanger to a temperature above the deposition temperature of the ammonium salts.
The cooled intermediate product may still remain at an undesirable temperature for further processing downstream of the hydro-pretreating system. Therefore, the cooled intermediate product may require additional cooling in the quenching and diluting step 294. To avoid deposition of the ammonium salts in the cooled intermediate product, a wash oil stream (e.g., hydrocarbon stream 170) generated in the separation system is added to the cooled intermediate product, thereby quenching and diluting it. In addition to the wash oil stream, a wash water stream (e.g., the wash water stream 164) also generated in the separation system is added to the cooled intermediate product, which further quenches the cooled intermediate product and dissolves the ammonium salts, HCl, and NH3 to generate a diluted intermediate product (e.g., the diluted intermediate product 162). As such, no ammonium salts deposit upon further cooling the cooled intermediate product to a temperature below the original desublimation temperature of the salt precursors. In this way, the process 280 disclosed herein mitigates deposition of ammonium salts in high chlorides feedstock downstream of the hydro-pretreating system. As such, contaminants such as chlorides and nitrogen present in the feedstock may not need to be removed upstream of the hydro-pretreating system.
The technical effects of hydroprocessing a high chloride feedstock using the system and method disclosed herein mitigate the undesirable impact of the deposition of ammonium salts, such as ammonium chloride, on system component surfaces and/or inlets. As such, systems used for hydroprocessing may be used for high chloride feedstocks without the need of complex pretreatment of these feeds to remove or decrease amounts of certain contaminants such as chlorides and nitrogen. Existing techniques utilize caustic washes and solvent extractions to remove or decrease the amount of chlorides in high chloride feedstocks that undergo hydroprocessing upstream of hydro-pretreatment systems. Caustic washing only removes a portion of chlorides, and solvent extraction generates an undesirable amount of hydrocarbon reject stream that is highly aromatic and contains an undesirable amount of chlorides. Therefore, disposal of these waste product streams may be difficult and costly. However, by using the system and method disclosed herein, the chlorides and other contaminants (e.g., NH3) may be removed downstream of a hydro-pretreating system without deposition of ammonium salts (e.g., ammonium chloride) that cause undesirable corrosion, fouling of equipment and/or plugging of system components prior to conversion steps such as hydrocracking or steam cracking. By using the heating system of the present disclosure, high chloride streams and system components may be maintained at temperatures above the deposition temperature of ammonium salts while also recovering heat from the high chloride streams that may be used elsewhere throughout the system. This improves the overall efficiency of the system and also reduces the overall operational costs as the heat generated by the system may be recovered and reused. In addition, certain effluent streams generated in, for example, a separation system may be used to quench and dilute high chloride streams. As such, deposition of the ammonium salts is avoided even after a temperature of the high chloride stream is decreased below the desublimation temperature of the salt precursors. Accordingly, the disclosed system and method provide an effective, efficient, and robust technique for hydroprocessing of high chloride feedstocks derived from SPW, fossil, biomass, and combinations thereof.
The present disclosure may be embodied in other specific forms without departing from its spirit or essential characteristics. The described embodiments are to be considered in all respects only as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by the appended claims rather than by the foregoing description. All changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.
| Number | Date | Country | Kind |
|---|---|---|---|
| 202241077440 | Dec 2022 | IN | national |
