CN118076713A - Method for producing kerosene and diesel oil from renewable resources - Google Patents

Abstract

A process for increasing the yield of kerosene from a renewable feedstock involves directing a hydrotreated liquid stream to a lead stripper to separate a lead stripper bottoms stream and a lead stripper overhead stream comprising naphtha, lower and higher boiling range hydrocarbons and water. A substantial amount of water is removed from the lead stripper overhead stream to yield an unstable hydrocarbon stream which is passed to a stabilizer column to separate a stabilized naphtha-containing stream from the lower boiling range hydrocarbons. The stabilized naphtha-containing stream is sent to a rectification column to separate a rectification column bottoms stream and a naphtha product stream. The kerosene and diesel boiling range product streams are separated from the lead stripper bottoms stream in a vacuum fractionator.

Description

Method for producing kerosene and diesel oil from renewable resources

Technical Field

The present invention relates to the field of producing kerosene and diesel oil from renewable resources, and in particular to a process for increasing the yield of kerosene and/or diesel oil from renewable resources.

Background

The increase in energy demand due to world economic growth and development has led to an increase in the concentration of greenhouse gases in the atmosphere. This is considered one of the most important challenges facing humans in the 21 st century. In order to mitigate the effects of greenhouse gases, efforts have been made to reduce the global carbon footprint. The earth's system's ability to absorb greenhouse gas emissions has been depleted. Thus, the goal was to achieve net zero emissions by 2050. To achieve these emissions reduction goals, the world is being transformed from purely conventional carbon-based fossil fuel energy carriers. Timely realization of energy conversion requires multiple processes in parallel including, for example, energy conservation, energy efficiency improvement, electrification, and efforts to produce fuels and fuel components and/or chemical feedstocks using renewable resources.

Vegetable oils, oils obtained from algae, and animal fats are considered renewable resources. Moreover, decomposed materials, such as pyrolyzed recyclable materials or wood, are considered potential resources.

Renewable materials can include materials with very high molecular weight and high viscosity such as triglycerides, which means that their use, either directly or as a mixture, for fuel bases is problematic for modern engines. On the other hand, the hydrocarbon chains constituting, for example, triglycerides are substantially linear, and their length (in terms of carbon number) is compatible with the hydrocarbons used/used as fuel. Therefore, it is attractive to convert a feed comprising triglycerides to obtain a high quality fuel component.

Petroleum derived jet fuels themselves contain paraffins and aromatics. Typically, paraffins provide the most desirable combustion cleanliness characteristics for jet fuels. Challenges in using paraffins from renewable sources include higher boiling points and higher freezing points due to chain length. Solutions to these challenges include cracking to reduce chain length and/or isomerization to increase branching, thereby lowering freezing point. Aromatic hydrocarbons typically have the least desirable combustion characteristics for aircraft turbine fuels. Certain aromatic hydrocarbons (such as naphthalene) tend to burn more heavily in flame smoke and release a greater proportion of chemical energy as undesirable heat radiation in aircraft turbines than other more saturated hydrocarbons.

Brady et al (US 8,193,400, 2012, 6, 5) relates to a process for producing a branched paraffin-rich diesel product by: the renewable feedstock is hydrodeoxygenated, a gas stream comprising H ₂、H₂ O and carbon oxides is separated from the normal paraffins in a hot high pressure hydrogen stripper, and the normal paraffins are isomerized to produce a stream rich in branched paraffins. The paraffin-rich stream is cooled and separated into (i) LPG and naphtha streams and (ii) a diesel boiling range stream. A portion of streams (i), (ii) or LPG and/or naphtha separated from stream (i) is recycled to the rectification zone of the hot high pressure stripper to increase the hydrogen solubility of the reaction mixture. The effluent from the hot high pressure stripper is then isomerized.

Similarly, brady et al (US 8,198,492, 2012, 6/12) relates to a process for producing diesel and aviation boiling products by: the renewable feedstock is hydrodeoxygenated and a gas stream comprising H ₂、H₂ O and carbon oxides is separated from the normal paraffins in a hot high pressure hydrogen stripper. The normal paraffins are isomerized and selectively cracked to produce a stream rich in branched paraffins. The paraffin-rich stream is cooled and separated into an overhead stream, a diesel boiling range product, and an aviation boiling range product. A portion of the diesel boiling range products, aviation boiling range products, naphtha products, and/or LPG is recycled to the rectification zone of the hot high pressure stripper to reduce the amount of product carried in the stripper overhead. The effluent from the hot high pressure stripper is then isomerized.

In Marker et al (US 8,314,274, 11/20 in 2012), renewable feedstocks are hydrodeoxygenated and then isomerized and selectively hydrocracked to produce an effluent comprising branched paraffins. The effluent is separated to provide an overhead stream, optionally an aviation product stream, a diesel stream, and a stream having a higher boiling point. A portion of the diesel boiling range products is recycled to the isomerization and selective hydrocracking zone.

Stewart et al (US 8,999,152, 4.7) address the challenge of maximizing diesel production from petroleum derived feeds while maintaining kerosene production. The hydrotreated effluent stream is stripped and the stripped effluent is separated into a heavy naphtha stream, a kerosene stream, and a diesel stream. The heavy naphtha stream is blended with the diesel stream to produce a blended diesel stream.

Ladkat et al (US 9,234,142, 2016, 1/12 and US10,041,008, 2018, 8/7) describe an apparatus for hydrotreating petroleum derived feeds. The cold hydrotreated effluent is sent to a cold stripper and a light fractionator while the hot hydrotreated effluent is sent to a hot stripper and a heavy fractionator.

There remains a need to increase the yield of kerosene from renewable resources.

Disclosure of Invention

According to one aspect of the present invention, there is provided a method for increasing the yield of kerosene from renewable raw materials, the method comprising the steps of: reacting the renewable feedstock in a hydrotreating zone under hydrotreating conditions sufficient to cause a hydrotreating reaction to produce a hydrotreated effluent; separating the hydrotreated effluent to produce at least one hydrotreated liquid stream and at least one offgas stream; directing the at least one hydrotreated liquid stream to a lead stripper to separate a lead stripper bottoms stream and a lead stripper overhead stream comprising naphtha, lower boiling range hydrocarbons, higher boiling range hydrocarbons, and water; condensing the lead stripper overhead stream and removing a substantial amount of water from the lead stripper overhead stream to obtain an unstable hydrocarbon stream; passing the unstable hydrocarbon stream to a stabilizer column to separate a stabilized naphtha-containing stream from the lower boiling range hydrocarbons; passing the stabilized naphtha-containing stream to a rectification column to separate a rectification column bottoms stream and a naphtha product stream; and passing the leading stripper bottoms stream to a vacuum fractionator to produce an overhead stream, a kerosene boiling range product stream, and a diesel boiling range product stream.

Drawings

The process of the present invention may be better understood by reference to the following detailed description of preferred embodiments and the accompanying drawings referred to therein, in which:

FIG. 1 is a schematic diagram showing a general overview of one embodiment of the method of the present invention;

FIG. 2 shows an embodiment of a post-treatment stage for use in the method of the invention; and

Figure 3 shows an embodiment of a vacuum fractionator zone for use in the process of the present invention.

Detailed Description

The present invention provides a method for increasing the yield of kerosene and/or diesel fuel in the hydrotreating of materials from renewable resources.

The process of the present invention is important for energy conversion and can improve the environment by producing low carbon energy and/or chemicals from renewable sources, particularly from degradable waste sources, while improving the energy efficiency of the process.

A common challenge in processing renewable feedstocks to produce kerosene and/or diesel is the variability of renewable feedstocks. Variability of renewable feedstocks may include changes from one type of feedstock to another, such as due to changes in supply and/or market, feedstock quality and/or composition distribution, seasonal changes, changes between identical feedstock sources, and the like. The reaction scheme, operating conditions, heat generation, process efficiency, product composition, and/or product yield may all be affected by such variability. Another challenge in meeting product specifications is that product component yields vary with changes in catalyst activity, and/or from start of run to end of run. The process of the present invention provides flexibility and robustness to allow for variability of feedstock, variation in catalyst activity, and/or variation in desired product while reducing energy consumption, operating costs, and/or carbon footprint. Furthermore, the process of the present invention can improve on existing process schemes for treating petroleum derived feedstocks.

In the process of the present invention, renewable feedstocks are reacted in a hydrotreating section to produce a hydrotreated effluent. Separating the hydrotreated effluent to produce at least one hydrotreated liquid stream and at least one offgas stream. One or more hydrocarbon liquid streams are directed to the post-treatment stage.

According to the post-treatment section of the present invention, one or more hydrotreated liquid streams are directed to a lead stripper. The lead stripper bottoms stream is separated from a lead stripper overhead stream comprising naphtha, lower and higher boiling range hydrocarbons and water. Condensing the lead stripper overhead stream and removing a substantial amount of water from the lead stripper overhead hydrocarbon stream, stabilizing the lead stripper overhead hydrocarbon stream in a stabilizer column, wherein H ₂ S, low boiling range hydrocarbons and water are removed. The stabilized naphtha-containing stream is sent to a rectification column to separate a rectification column bottoms stream and a naphtha product stream. The stripper bottoms from the lead stripper is substantially free of naphtha and aqueous phase. The stripper bottoms stream from the lead stripper is sent to a vacuum fractionator to separate a top stream, a kerosene boiling range product stream, and a diesel boiling range product stream.

The inventors have found that by removing a significant amount of water and naphtha boiling range products from higher boiling range hydrocarbons, a vacuum can be effectively drawn in the vacuum fractionator resulting in much lower operating temperatures and energy recovery using lower higher kerosene. As will be discussed in more detail below, lower operating temperatures in the vacuum fractionator enable energy savings and reduced carbon footprint. In addition, the separate naphtha processing section can achieve more consistent higher value product (such as kerosene and/or diesel) yields.

Embodiments of process units for carrying out the method of the invention are described below and/or shown in the drawings. For ease of discussion, additional equipment and process steps that may be used in the process for producing kerosene and/or diesel fuel from renewable feedstocks are not shown. Additional equipment and/or process steps may include, for example, but not limited to, pre-processors, heaters, coolers, air coolers, heat exchangers, mixing chambers, valves, pumps, compressors, condensers, quench streams, recycle streams, slip streams, purge streams, reflux streams, and the like.

Fig. 1 shows a general overview of one embodiment of the method 10 of the present invention. Renewable feedstock 12 is reacted in hydrotreating section 14 to produce hydrotreated effluent 16. The hydrogen may be combined with the renewable feedstock 12 stream prior to its introduction into the hydrotreating section 14, co-fed with the renewable feedstock 12, or added to the hydrotreating section 14 separately from the renewable feedstock 12. The hydrogen may be fresh and/or recycled from another unit in the process and/or produced in an HMU (not shown). In another embodiment, the hydrogen may be generated in situ in the reactor or process, such as, but not limited to, by electrolysis of water. The water electrolysis process may be powered by renewable energy sources such as solar photovoltaic, wind or hydro electricity, generating green hydrogen, nuclear energy, or by non-renewable energy sources from other sources (gray hydrogen).

As used herein, the terms "renewable feedstock", "renewable feedstock" and "material from renewable sources" refer to feedstock from renewable sources. The renewable sources may be animal, plant, microbial and/or bio-derived or mineral derived waste materials suitable for the production of fuels, fuel components and/or chemical feedstocks.

One preferred class of renewable materials are bio-renewable fats and oils comprising triglycerides, diglycerides, monoglycerides, free fatty acids and/or fatty acid esters derived from bio-renewable fats and oils. Examples of fatty acid esters include, but are not limited to, fatty acid methyl esters and fatty acid ethyl esters. Bio-renewable fats and oils are edible and non-edible fats and oils. Examples of bio-renewable fats and oils include, but are not limited to, algae oil, brown grease, canola oil, fossil-bone rape oil, castor oil, coconut oil, rapeseed oil, corn oil, cottonseed oil, fish oil, jatropha oil, lard, linseed oil, milk fat, mustard oil, olive oil, palm oil, peanut oil, rapeseed oil, water yellow oil, sewage sludge, soybean oil, sunflower oil, tall oil, tallow, used cooking oil, yellow grease, white grease, and combinations thereof.

Another preferred class of renewable materials are liquids derived from biomass and waste liquefaction processes. Examples of such liquefaction processes include, but are not limited to, (hydro) pyrolysis, hydrothermal liquefaction, plastic liquefaction, and combinations thereof. Renewable materials derived from biomass and waste liquefaction processes may be used alone or in combination with bio-renewable fats and oils.

Renewable materials used as feedstock in the process of the present invention may contain impurities. Examples of such impurities include, but are not limited to, solids, iron, chloride, phosphorus, alkali metals, alkaline earth metals, polyethylene, and unsaponifiable compounds. These impurities can be removed from the renewable feedstock, if desired, prior to introduction into the process of the present invention. Methods for removing these impurities are known to those skilled in the art.

The process of the present invention is most advantageous when treating a feed stream comprising substantially 100% renewable raw materials. However, in one embodiment of the invention, the renewable feedstock may be co-processed with petroleum-derived hydrocarbons. Petroleum derived hydrocarbons include, but are not limited to, all fractions from petroleum crude oil, natural gas condensate, tar sands, shale oil, synthetic crude oil, and combinations thereof. The present invention is more advantageous for renewable and petroleum-derived combined feedstocks comprising renewable feed contents in the range of 30 wt.% to 99 wt.%.

In the hydrotreating section 14, the renewable feedstock 12 is reacted under hydrotreating conditions sufficient to cause a reaction selected from the group consisting of hydrogenation, hydrotreating (including but not limited to hydrodeoxygenation, hydrodenitrogenation, hydrodesulfurization, and hydrodemetallization), hydrocracking, selective cracking, hydroisomerization, and combinations thereof. The reaction is preferably a catalytic reaction, but may include non-catalytic reactions such as heat treatment and the like. The hydrotreating section 14 may be single stage or multi-stage. The hydrotreating section 14 may be comprised of a single reactor or multiple reactors. In the case of catalytic reactions, the hydrotreating section 14 may be operated in slurry, fluidized bed, and/or fixed bed operations. In the case of fixed bed operation, each reactor may have a single catalyst bed or multiple catalyst beds. The hydrotreating section 14 may be operated in a co-current mode, a counter-current mode, or a combination thereof.

An example of a single stage reaction is disclosed in van Heuzen et al (US 8,912,374, day 16 of 2014, 12) wherein hydrogen and renewable feedstock are reacted with a hydrogenation catalyst under hydrodeoxygenation conditions. All of the effluent from the hydrodeoxygenation reaction is contacted with a catalyst under hydroisomerization conditions. The single-stage reaction may be carried out in a single reactor vessel or in two or more reactor vessels. The process may be carried out in a single catalyst bed, for example using a multifunctional catalyst. Alternatively, the process may be conducted in a stacked bed configuration, wherein the first catalyst composition is stacked on top of the second catalyst composition.

The catalysts may be the same, a mixture, or different throughout the hydrotreating section 14. The hydrotreating section 14 may include a single catalyst bed or multiple catalyst beds. The catalyst may be the same throughout a single catalyst bed, optionally with a mixture of catalysts present, or different catalysts may be provided in two or more layers in the catalyst bed. In embodiments of multiple catalyst beds, the catalyst for each catalyst bed may be the same or different.

The hydrogenation component may be used in bulk metal form or the metal may be supported on a carrier. Suitable carriers include refractory oxides, molecular sieves, and combinations thereof. Examples of suitable refractory oxides include, but are not limited to, alumina, amorphous silica-alumina, titania, silica, and combinations thereof. Examples of suitable molecular sieves include, but are not limited to, zeolite Y, zeolite beta, ZSM-5, ZSM-12, ZSM-22, ZSM-23, ZSM-48, SAPO-11, SAPO-41, ferrierite, and combinations thereof.

The hydrotreating catalyst may be any catalyst known in the art to be suitable for hydrotreating. The catalyst metal is typically in the oxide state when charged to the reactor and is preferably activated by reduction or sulfiding of the metal oxide. Preferably, the hydrotreating catalyst comprises a group VIII and/or group VIB catalytically active metal, including but not limited to Pd, pt, ni, co, mo, W and combinations thereof. Hydrotreating catalysts are generally more active in the sulfided form than in the oxide form of the catalyst. The sulfiding process is used to convert the catalyst from a calcined oxide state to an active sulfided state. The catalyst may be presulfided or sulfided in situ. Because renewable feedstocks typically have low sulfur content, sulfiding agents are often added to the feed to maintain the catalyst in sulfided form.

Preferably, the hydrotreating catalyst comprises sulfided catalytically active metal. Examples of suitable catalytically active metals include, but are not limited to, nickel sulfide, cobalt sulfide, molybdenum sulfide, tungsten sulfide, coMo sulfide, niMo sulfide, moW sulfide, niW sulfide, and combinations thereof. The catalyst beds/zones may have a mixture of two types of catalysts and/or successive beds/zones, including stacked beds, and may have the same or different catalysts and/or catalyst mixtures. In the case of using such sulfided hydrotreating catalysts, a sulfur source is typically provided to the catalyst to maintain the catalyst in sulfided form during the hydrotreating step.

The hydrotreating catalyst may be sulfided in situ or ex situ. In situ sulfiding may be achieved by supplying a sulfur source, typically H ₂ S or H ₂ S precursor (i.e. a compound that readily decomposes to H ₂ S, such as, for example, dimethyl disulfide, di-t-nonyl polysulfide or di-t-butyl polysulfide), to the hydrotreating catalyst during operation of the process. The sulfur source may be supplied with the feed, the hydrogen stream, or separately. Another suitable sulfur source is a sulfur-containing hydrocarbon stream co-fed with the feedstock that has a boiling point in the diesel or kerosene boiling range. In addition, the sulfur compound added in the feed is beneficial to controlling the stability of the catalyst and can reduce the consumption of hydrogen.

Preferably, the hydrotreating reaction includes a hydroisomerization reaction to increase branching, thereby lowering the freezing point of the fuel.

The hydrotreating section 14 may be operated as a single stage process or a multi-stage process. In a preferred embodiment, the hydrotreating section 14 operates as a single stage process, employing a co-current mode with one or more fixed beds. In one embodiment, the hydrotreating section 14 has a single hydrotreating reactor with one or more catalyst beds with the same multi-functional catalyst composition for catalyzing at least one hydrotreating reaction (preferably hydrodeoxygenation) and hydroisomerization reaction. In another embodiment, the hydrotreating section 14 has a single hydrotreating reactor in which a first catalyst composition having hydrotreating functionality is stacked on top of a second catalyst composition having isomerization functionality. In another embodiment, the hydrotreating section 14 has two or more hydrotreating reactors for at least two catalyst compositions. In yet another embodiment, the isomerization catalyst may also include a selective cracking function. Alternatively, the selective cracking catalyst may be provided in the same or different beds. Different numbers of catalyst beds may be used in each hydrotreating reactor.

The hydrotreated effluent 16 is then directed to a separation system 20 and a post-treatment stage 100 to separate an overhead stream, a kerosene boiling range product stream 52, and a diesel boiling range product stream 54.

In another preferred embodiment, the hydrotreating section 14 operates as a multi-stage process, employing a co-current mode with one or more fixed beds.

In one embodiment, the hydrotreating section 14 has two hydrotreating reactors. In another embodiment, the hydrotreating section 14 has three hydrotreating reactors, with the first and second reactors operating as a single stage and the second and third reactors operating in a multi-stage configuration with an intermediate separation system 20. Alternatively, the first and second reactors may be operated in a multi-stage configuration with an intermediate separation system that may share some or all of the separator units of the separation system 20 between the second and third reactors.

The hydrotreating reactors may each independently have one or more catalyst beds. The type of catalyst used in each hydrotreating reactor may be the same or different. In a preferred embodiment, the first catalyst is a hydrotreating catalyst and the second catalyst is a hydroisomerization catalyst. In a preferred embodiment, a separation system 20 is provided between the hydrotreating and hydroisomerization zones/reactors. The hydrotreated effluent from the hydrotreatment zone/reactor is separated to produce one or more hydrotreated liquid streams 32 and one or more separation system exhaust streams 34. All or a portion of the hydrotreated liquid stream 32 is directed to the hydroisomerization reactor/zone.

The hydrotreated effluent 16 from the one or more separator units and a portion of the hydrotreated liquid stream 32 can be returned to the first hydrotreatment reactor, for example, as a quench stream (not shown) or as a diluent (not shown) for the feedstock 12. The hydrotreated effluent from the second and/or third hydrotreating reactor/zone can be directed to one or more separation units or different separators of separation system 30 and then to post-treatment stage 100.

The hydrotreated effluent 16 is directed to a separation system 20 to produce at least one hydrotreated liquid stream 22 and at least one separation system exhaust stream 24.

The separation system 20 has one or more separation units including, for example and without limitation, gas/liquid separators including hot high pressure and low pressure separators, medium high pressure and low pressure separators, cold high pressure and low pressure separators, strippers, integrated strippers, and combinations thereof. The integrated stripper includes a stripper integrated with a hot high pressure and low pressure separator, a medium high pressure and low pressure separator, a cold high pressure and low pressure separator. Those skilled in the art will appreciate that the high pressure separator operates at a pressure approaching that of the hydrotreating section 14, suitably from 0 bar to 10 bar (0 MPa to 1 MPa) below the reactor outlet pressure, while the low pressure separator operates at a pressure below that of the previous reactor or the previous high pressure separator in the hydrotreating section 14, suitably from 0 bar to 15 bar (0 MPaG to 1.5 MPaG). Similarly, one skilled in the art will understand that by hot is meant that the hot separator is operated at a temperature near the temperature of the previous reactor in the hydrotreating section 14, which is suitably well above the dew point of water (e.g., above the dew point of water by ≡20 ℃, preferably ≡10 ℃) and well above the salt deposition temperature (e.g., above the salt deposition temperature by ≡20 ℃, preferably ≡10 ℃), while the intermediate separator and the cold separator are at a reduced temperature relative to the previous reactor in the hydrotreating section 14. For example, the cold separator is suitably at a temperature achievable by an air cooler. Intermediate temperature is understood to mean any temperature between the temperatures of the hot separator or the cold separator.

In addition, separation system 20 may include one or more processing units including, for example, but not limited to, a membrane separation unit, an amine scrubber, a Pressure Swing Adsorption (PSA) unit, a caustic wash, and combinations thereof. The treatment unit is preferably selected to separate the desired gas phase molecules. For example, an amine scrubber is used to selectively separate H ₂ S and/or carbon oxides from H ₂ and/or hydrocarbons. As another example, a PSA unit can be used to purify the hydrogen stream for recycle to the stripper and/or reactor in the hydrotreating section 14.

The hydrotreated effluent from one or more reactors in the hydrotreating section 14 may each be treated in a separate embodiment of the separation system 20. The effluents from the different reactors/zones may be treated in all or some of the same separation units.

In one embodiment, separation system 20 includes a Hot Separator (HS) (such as a hot high pressure separator, a hot low pressure separator, and/or an integrated stripper separator) and a Cold Separator (CS) (such as a cold high pressure separator and/or a cold low pressure separator). In addition to the light hydrocarbons, CO ₂, carbon monoxide, and H ₂ S, HS flashes off hydrogen-rich gas from the hydrotreated effluent, producing a hydrotreated liquid stream 22 and/or an inter-stage liquid stream. The inter-stage liquid stream is directed, in whole or in part, to a subsequent hydrotreating zone and/or reactor. All or a portion of the hydrotreated liquid stream 22 is directed to the post-treatment stage 100. The HS off-gas is then cooled, for example in an air cooler (not shown) or heat exchanger (not shown), and directed to the CS, where at least a portion of the light hydrocarbons are separated from the HS off-gas stream as a liquid effluent stream, preferably combined with the effluent from another hydrotreating zone/reactor and/or the hydrotreated liquid stream 22. The exhaust gas flow 24 may be directed to a gas treatment section 30, a gas treatment unit, or for another purpose.

A portion of the liquid effluent from the HS and/or CS may be recycled and/or used as diluent and/or quench stream between catalyst beds in one or more reactors in the hydrotreating section 14. For example, by recycling from the HS, the operating costs from pumping and/or heating may be reduced.

In one embodiment, the separation system 20 includes HS, CS, and PSA units. All or a portion of the waste gas stream from the CS is directed to a PSA unit to separate a hydrogen-rich stream from the CS waste gas stream. The hydrogen-rich stream may be recycled to one or more reactors in the hydrotreating section 14, the separation system 20, or a stripper in the post-treatment section 100, and/or another treatment unit in the refinery. The hydrogen-rich stream may be compressed in a compressor prior to recycle. The exhaust flow 24 may also include a portion of the exhaust from the HS and/or CS. The exhaust gas flow 24 may be directed to a gas treatment section 30, another gas treatment unit (not shown), or for another purpose.

In yet another embodiment, the separation system 20 includes an HS, a CS, and an amine scrubber. The effluent gas stream from the CS is directed to an amine scrubber to separate a hydrogen-rich stream from the CS effluent gas stream.

Optionally, all or a portion of the exhaust gas stream from the CS is first directed to the PSA and then the tail gas therefrom is directed to the amine scrubber. In this embodiment, the tail gas from the PSA is typically at a lower pressure than the amine scrubber. Thus, it may be desirable to compress the PSA tail gas before directing the tail gas to an amine scrubber. Alternatively, the PSA tail gas may be directed as the exhaust gas stream 24 for treatment in the gas treatment section 30 prior to being directed to the amine scrubber.

The hydrogen-rich stream from the amine scrubber and/or PSA unit can be recycled to one or more reactors in the hydrotreating section 14, the stripper in the separation system 20 or the finishing section 100, and/or another treatment unit. The hydrogen-rich stream may be compressed in a compressor prior to recycle.

The amine scrubber may be a scrubber for carbon monoxide removal containing Monoethanolamine (MEA), diethanolamine (DEA), methyldiethanolamine (MDEA), promoted MEA, DEA and/or MDEA, activated MEA, DEA and/or MDEA, and combinations thereof. The exhaust flow 24 may also include a portion of the exhaust from the HS and/or CS. Preferably, the rich amine stream from the amine scrubber is regenerated in a low pressure amine regenerator and the off-gas from the top of the amine generator can be directed to the gas treatment section 30. The exhaust gas flow 24 may be directed to a gas treatment section 30, another gas treatment unit, or for another purpose.

Those skilled in the art will appreciate that the same or different separation units and/or treatment units may be disposed between and/or after the catalyst zones in the hydrotreating section 14, as well as between and/or after the components of the gas treatment section 30 and/or the post-treatment section 100.

The separation system exhaust gas flow 24 is directed to a gas treatment section 30. The gas stream in the gas treatment section 30 is preferably subjected to a pressurizing and/or cooling operation to obtain a pressurized gas stream 34 and a hydrocarbon fraction 32. Examples of suitable equipment for the gas treatment section 30 include, but are not limited to, compressors, heat exchangers, ejectors, knock-out pots, dryers, turbines, and combinations thereof.

The hydrocarbon fraction 32 from the gas treatment section 30 may be sent to the post treatment section 100 or another stream or unit in the process.

The one or more hydrotreated liquid streams 22 are directed to the post-treatment stage 100. Referring now to fig. 2, the one or more hydrotreated liquid streams 22 are directed to a lead stripper 112 where a lead stripper overhead stream 116 is separated from a lead stripper bottoms stream 114 using a stripper gas 118. Stripper gases include, but are not limited to, steam, hydrogen, methane, nitrogen, and the like. Some stripping gases may be less efficient than others and/or additional process equipment may be required. Thus, the preferred stripper gas 118 is steam in view of the low molecular weight and relatively high condensing temperature.

Naphtha from hydrotreated liquid stream 22 is stripped from higher boiling hydrocarbons in accordance with the invention and carried from lead stripper 112 in stripper overhead stream 116. In addition to naphtha, the stripper overhead stream also includes lighter and heavier hydrocarbons from the stripping gas 118, H ₂ S and water and/or any residual water from the separation system 20.

The lead stripper 112 is operated at a temperature and pressure that allows for the separation of naphtha and water from the higher boiling hydrocarbons. Preferably, the lead stripper 112 is operated at a temperature and pressure range that avoids the water dew point in the lead stripper 112 and provides for optimal recovery of the product naphtha, with the final temperature profile depending on the pressure chosen for the particular design. The design pressure will, in turn, depend on, for example, the type of equipment, such as the presence or absence of a compressor, etc. As one example, the lead stripper 112 may be operated at a temperature in the range of about 150 ℃ to 280 ℃, preferably in the range of about 180 ℃ to 220 ℃, and a pressure in the range of about 2 bar to 12 bar (0.2 mpa g to 1.2mpa g), preferably in the range of about 5bar to 8 bar (0.5 mpa g to 0.8mpa g). Preferably, the hydrotreated liquid stream 22 is fed to the lead stripper 112 at a suitable temperature to allow the lead stripper 112 to operate at a temperature above the dew point of water. In addition, the higher temperature in the lead stripper 112 reduces slippage of naphtha to the stripper bottoms 114, thereby improving the operation of the vacuum fractionator, as will be discussed in more detail below. A heat exchanger (not shown) may be provided to heat the hydrotreated liquid stream 22 prior to feeding it to the lead stripper 112.

A large amount of water 124 is condensed in a condenser or accumulator 122 and separated as a liquid stream from the lead stripper overhead stream 116. A small portion of H ₂ S may be dissolved in the condensed water. The resulting unstable hydrocarbon stream 126 containing light and heavy hydrocarbons may still include saturated water and/or entrained water that has not been removed in the condenser or accumulator 122. The unstable hydrocarbon stream 12 is sent to a naphtha stabilizer 128 to remove a stabilizer overhead stream 132 containing H ₂ S, water, and light hydrocarbons. All or a portion of the stabilizer overhead stream 132 can be returned to the lead stripper overhead stream 116 upstream of the condenser or accumulator 122 to reabsorb the naphtha component from the stabilizer overhead.

The lead stripper 112, condenser or accumulator 122 and naphtha stabilizer 128 are preferably operated at a pressure selected by a common pressure controller to maintain the lead stripper 112 above the water dew point. The combined overheads avoid the need for a compressor or dedicated overhead tank and pump for the stabilizer column 128 and use the stripper overheads as a sponge absorber for the naphtha component.

The stabilized naphtha-containing stream 134 is passed from the naphtha stabilizer 128 to a rectifier 136 where a naphtha product stream 138 is separated from a rectifier bottoms stream 142 containing higher boiling range hydrocarbons. The rectification bottoms stream 142 is recycled to the lead stripper 112.

By separating the naphtha boiling range hydrocarbons in the overhead of the lead stripper 112, the naphtha product 138 is provided as a clean and stable product stream free of water and H ₂ S, thereby reducing any accumulation of light naphtha components that may occur in the overhead stream of a typical lead stripper where naphtha is recovered in the bottom stream. In addition, this allows Medium Pressure (MP) steam to be used for a corresponding reboiler (not shown).

One of the advantages of the present invention is that when there is variability in the renewable feedstock being processed, the process can be flexibly changed on the fly to meet the product specifications of kerosene and/or diesel. Variability of renewable feedstocks may include changes from one type of feedstock to another, such as due to changes in supply and/or market, feedstock quality and/or composition distribution, seasonal changes, changes between identical feedstock sources, and the like. For example, hydrotreating some feedstocks will produce lower levels of naphtha than other feedstocks. Typical yields of naphtha are 10 wt.% to 15 wt.% based on the feed. Depending on the feedstock, the desired products (diesel and kerosene), the degree of catalyst deactivation and/or whether the process is in the start-up stage, the amount of naphtha yield may be very low, for example 1 wt-%.

The process 100 of the present invention allows for recycling of the naphtha product stream 138 and/or the rectification bottoms stream 142. For example, a portion or all of the naphtha product stream 138 may be temporarily recycled to the condenser or accumulator 122. Further, a portion or all of the rectification column bottom stream 142 can be temporarily directed to the stripper overhead stream 116 upstream of the condenser or accumulator 122. Another advantage of the recycle stream achieved by the method of the present invention is that it provides a means for adjusting the Log Mean Temperature Difference (LMTD) across the reboilers (not shown) of the stabilizer column 128 and rectifier column 136. For example, when very little naphtha is present, the temperature of the stabilizer 128 may be too high to use MP steam for the reboiler. Recycling a portion or all of naphtha product stream 138 may allow for smaller reboiler sizes and/or the ability to use lower quality heat media for the reboiler.

Preferably, the reboiler for the stabilizer column 128 has a circulating thermosiphon reboiler configuration to further allow a wide operating range. Preferably, the reboiler for the rectification column 136 has a forced circulation configuration to enhance the robustness of the process over a wide operating range.

The leading stripper bottoms stream 114 is sent to a vacuum fractionator 150. In accordance with the present invention, the leading stripper bottoms stream 114 is substantially free of substantial amounts of water and naphtha boiling range and lower boiling hydrocarbons are substantially removed. This improves the operation of the vacuum fractionator 150 by reducing the energy consumption of the vacuum system. In addition, because a majority of the naphtha product is recovered in another unit, the vacuum fractionator 150 can be operated without the capital and operating expense associated with injection side stripper, as required in conventional processes. Furthermore, by using a vacuum fractionator, the yield of kerosene products can be increased without the need for a heating furnace to heat the feed (e.g., in a fired heater) and the associated operating and energy costs.

The vacuum fractionator 150 is preferably a packed column. Filling under vacuum can be more efficient than atmospheric fractionation.

Turning now to fig. 3, an embodiment of a vacuum fractionator zone 160 for use in the process 10 of the present invention is shown, the leading stripper bottoms stream 114 being directed to a vacuum fractionator 150. Vacuum fractionator 150 may operate at vacuum pressures ranging from light to deep vacuum, depending on the composition of the lead stripper bottoms stream 114 and the desired product yield. For a given column diameter, the vacuum fractionator 150 of the present invention provides a range of applied vacuum pressures. In this way, the vacuum pressure may be adjusted according to the available heat medium 154 in the reboiler 152. In the embodiment shown in fig. 3, the reboiler is a forced circulation reboiler that uses pump 156 to circulate a portion of the diesel boiling range product stream 54. Product stream 54 is vaporized by thermal medium 154 and returned to vacuum fractionator 150 to drive fractionation. The thermal medium 154 may be selected from steam, hot oil, and/or the hydrotreatment reactor effluent 22.

The lead stripper bottoms stream 114 is optionally preheated with a heat exchanger (not shown) to provide a treatment for reducing reboiler 152 duty requirements and also to allow for a reduction in reboiler recycle rate. This flexibility is particularly advantageous in certain yield situations, for example when the LMTD of the reboiler is relatively low.

A portion of the kerosene boiling range product stream 52 is returned to the vacuum fractionator 150 via a kerosene reflux stream 158, a top recycle reflux stream 162, and optionally a cold front end reflux stream 164 to cool and/or condense vapors in the vacuum fractionator 150. In a preferred embodiment, the cold front end reflux stream 164 works with the top recycle reflux stream 162 to fine tune the kerosene recovery.

In a preferred embodiment, the overhead stream 166 from the vacuum fractionator 150 is sent to an overhead condenser 168 along with a fuel gas 172. A heavy naphtha effluent recycle stream 174 is provided to the lead stripper overhead stream 116 to account for any naphtha slip in the feed to the vacuum fractionator 150.

The method 10 of the present invention allows for variability of renewable feedstocks, including changes from one type of feedstock to another, such as due to supply and/or market, changes in feedstock quality and/or composition distribution, seasonal changes, changes between identical feedstock sources, and the like. The process of the present invention 10 provides flexibility in meeting the specifications of diesel and/or kerosene products despite variations in reaction schemes, operating conditions, heat generation, process efficiency, product composition and/or product yield affected by such variability, even variations in product component yields and/or variations from start of run to end of run due to variations in catalyst activity. The method 10 of the present invention provides flexibility and robustness to allow for variability of feedstock, variation in catalyst activity, and/or variation in desired product while reducing energy consumption, operating costs, and/or carbon footprint. Furthermore, the process of the present invention can improve on existing process schemes for treating petroleum derived feedstocks.

While embodiments have been described with reference to various embodiments and modes of use, it should be understood that these embodiments are illustrative and that the scope of the inventive subject matter is not limited in this respect. Many variations, modifications, additions, and improvements are possible. Various combinations of the techniques provided herein may be used.

Claims (10)

1. A process for increasing the yield of kerosene from renewable raw materials, the process comprising the steps of:

reacting the renewable feedstock in a hydrotreating zone under hydrotreating conditions sufficient to cause a hydrotreating reaction to produce a hydrotreated effluent;

separating the hydrotreated effluent to produce at least one hydrotreated liquid stream and at least one offgas stream;

directing the at least one hydrotreated liquid stream to a lead stripper to separate a lead stripper bottoms stream and a lead stripper overhead stream comprising naphtha, lower boiling range hydrocarbons, higher boiling range hydrocarbons, and water;

Condensing the lead stripper overhead stream and removing a substantial amount of water to obtain an unstable hydrocarbon stream;

Passing the unstable hydrocarbon stream to a stabilizer column to separate a stabilized naphtha-containing stream from the lower boiling range hydrocarbons;

passing the stabilized naphtha-containing stream to a rectification column to separate a rectification column bottoms stream and a naphtha product stream; and

The leading stripper bottoms stream is passed to a vacuum fractionator to produce an overhead stream, a kerosene boiling range product stream, and a diesel boiling range product stream.

2. The process of claim 1, wherein at least a portion of the rectification column bottoms stream is recycled to the lead stripper.

3. The process of claim 1, wherein at least a portion of the naphtha product stream is recycled to the step of removing water from the stripper overhead stream.

4. The process of claim 1, wherein at least a portion of the rectification column bottoms stream is recycled to the step of removing water from the stripper overhead column.

5. The process of claim 1, wherein the temperature of the hydrotreated liquid stream is controlled to a temperature above the dew point of water in the lead stripper.

6. The process according to claim 1, wherein the lead stripper is operated at a pressure in the range of 1 bar to 10 bar (0.1 MPa to 1 MPa) above atmospheric pressure.

7. The method of claim 1, wherein the hydrotreating reaction is selected from the group consisting of hydrogenation, hydrotreating, hydrocracking, hydroisomerization, selective cracking, and combinations thereof.

8. The method of claim 1, wherein the effluent separation step comprises directing the effluent to one or more separator units selected from the group consisting of a hot high pressure separator, a hot low pressure separator, a medium high pressure separator, a medium low pressure separator, a cold high pressure separator, a cold low pressure separator, a stripper, an integrated stripper, and combinations thereof.

9. The method of claim 1, wherein the renewable feedstock is selected from the group consisting of one or more of bio-renewable fats and oils, liquids derived from biomass liquefaction processes, liquids derived from waste liquefaction processes, and combinations thereof.

10. The method of claim 1, further comprising adding a petroleum-derived feedstock for co-processing with the renewable feedstock, preferably in an amount to produce a feed stream comprising 30 wt% to 99 wt% renewable feedstock.