A process for producing hydrocarbon fractions having sustainable content and hydrocarbon fractions obtainable by said process

Abstract

A process for producing hydrocarbon fractions having sustainable content is provided In the process, a hydrotreatment feed having petroleum content as well as renewable and / or circular content is subjected to hydrotreatment to obtain a hydrotreatment effluent, which is fed to a separation stage from which at least three different distillates and a separation stage bottom are recovered. A residual marine fuel component is further recovered from the separation stage bottom. A hydrocracking feed comprising a portion of the separation stage bottom is subjected to hydrocracking to obtain a hydrocracking effluent, which is co-fed with the hydrotreatment effluent to the separation stage.

Description

[0001] A PROCESS FOR PRODUCING HYDROCARBON FRACTIONS HAVING SUSTAINABLE CONTENT AND HYDROCARBON FRACTIONS OBTAINABLE BY SAID PROCESS

[0002] TECHNICAL FIELD

[0003] The present disclosure generally relates to a process for producing hydrocarbon fractions having sustainable content. The disclosure relates particularly, though not exclusively, to a process for producing at least three different distillates, and a separation stage bottom. The disclosure also relates to a naphtha fraction, an aviation fuel range fraction, a light gas oil fraction, a middle gas oil fraction, a heavy gas oil fraction, and a residual marine fuel component, preferably obtainable by a process according to the present disclosure.

[0004] BACKGROUND

[0005] This section illustrates useful background information without admission of any technique described herein representative of the state of the art.

[0006] There is an ongoing need to reduce greenhouse gas (GHG) emissions and / or carbon footprint in the transportation and petrochemical industry. Accordingly, interest towards sustainable materials usable in these fields is growing.

[0007] Various processes for producing sustainable materials have been proposed. The first- generation biofuels, such as biodiesel (FAME) and bioethanol, are typically based on energy crops, limiting their environmental benefits in terms of GHG emissions. Also incompatibility issues when blended with fossil materials and in combustion systems have been of concern. Drawbacks reported for FAME, such as high viscosity, low energy content, high oxygen and water content, poor cold properties such as poor cloud and pour points, pose technical limitations to its usability, and also prevent its use as an aviation fuel.

[0008] Due to the disadvantages of the first-generation biofuels, alternative biofuels technologies are being explored, including concepts dedicated for processing non-petroleum feeds, but also co-processing concepts. For example, co-processing of biomass-derived streams in existing petroleum refineries has a growing interest not least because of the existing infrastructure, which allows instant implementation and reduced investment costs. One of the most studied technologies for co-processing concepts is fluid catalytic cracking (FOG), which is a widely used process in petroleum refineries for converting heavy fractions of crude oil to gasoline and propylene as the key products. However, this technology is not well suited for producing higher value products, such as fractions usable in aviation fuels. Additionally, catalyst regeneration which is necessarily required in a FCC unit involves high CO2 emissions, even 25-35% of the total CO2 emissions of a conventional petroleum refinery.

[0009] SUMMARY

[0010] It is an aim to solve or alleviate at least some of the problems related to prior art, including reducing GHG emissions and dependence from petroleum sources, especially in the transportation and petrochemicals sectors. An aim is to provide a process having an improved overall economy. Another aim is to provide a process producing a product slate having higher overall value and improved flexibility regarding the products that may be recovered. Afurther aim is to improve the yield of fractions having sustainable i.e. renewable and / or circular content.

[0011] The appended claims define the scope of protection. Any examples and technical descriptions of products, processes, and / or uses in the description and / or drawings not covered by the claims are presented as examples useful for understanding the invention.

[0012] According to a first example aspect, there is provided a process for producing hydrocarbon fractions, the process comprising: a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste to a pre-hydroconversion in a pre-hydroconversion reactor in the presence of a pre-hydroconversion catalyst to obtain a pre-hydroconversion effluent, and co-feeding a petroleum feed to the pre-hydroconversion reactor and / or combining a petroleum feed with at least a fraction of the prehydroconversion effluent, to obtain a hydrotreatment feed having petroleum content as well as renewable and / or circular content, b) subjecting the hydrotreatment feed to hydrotreatment in a hydrotreatment reactor in the presence of a hydrotreatment catalyst to obtain a hydrotreatment effluent, c) introducing at least a portion of the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least three different distillates, and a separation stage bottom having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, d) recovering a residual marine fuel component from the separation stage bottom, preferably by splitting a portion from the separation stage bottom, e) subjecting a hydrocracking feed comprising a portion of the separation stage bottom to hydrocracking in a hydrocracking reactor in the presence of a hydrocracking catalyst to obtain a hydrocracking effluent, and co-feeding at least a portion of the hydrocracking effluent with the hydrotreatment effluent to the separation stage.

[0013] The inventors have found the present process and embodiments thereof to provide certain advantages compared to prior art processes co-processing petroleum feed(s) and sustainable i.e. renewable and / or circular feed(s). The advantages are related e.g to reduced GHG emissions and reduced dependence from the diminishing petroleum sources, especially in the transportation but also in the petrochemical sector, as well as to improved overall economy of the process, improved flexibility regarding usable feedstocks and obtainable products, and higher overall value of the product slate. Further advantages are related to improved yield of fraction(s) having sustainable i.e. renewable and / or circular content. The pre-hydroconversion may comprise pre-hydrotreatment and / or prehydrocracking, and hence involve at least some cracking of the carbon backbones of the molecules in the vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and / or liquefied organic waste. Processing of the pre-hydroconversion effluent in the present process, which also includes hydrotreatment and hydrocracking steps, may further spread the renewable and / or circular content over a wider boiling range, so that essentially all the fractions recovered from the separation stage may have even significant renewable and / or circular content. As the process steps may be conducted under high hydrogen pressure, presence and formation of olefins may be minimised, thereby achieving product fractions having i.a. good stability. Benefits of the present process further include that there are virtually no restrictions how much renewable and / or circular content may be incorporated in the hydrotreatment feed in view of hydrotreatment reactor exotherm and / or corrosion risk mitigation, as the pre-hydroconversion efficiently reduces content of heteroatoms and other impurities, and hence also acidity that might pose corrosion issues. In this way even highly challenging renewable and / or circular feedstocks may be introduced, as pre-hydroconverted, into conventional petroleum refinery units.

[0014] The above-mentioned advantages may be attained with reduced costs, especially when utilising existing assets of a petroleum refinery. The present process is well suited for running in conventional or existing petroleum refinery units. Only the pre-hydroconversion reactor may need to be made of higher metallurgy grade than typical petroleum refinery units. Hence, in certain preferred embodiments, at least one or more, preferably at least two or more, more preferably at least three or more of the hydrotreatment reactor, the hydrotreatment catalyst, the separation stage, the hydrocracking reactor, and / or the hydrocracking catalyst are as originally configured to treat a petroleum feed.

[0015] When desired, the pre-hydroconversion effluent may be fed to a pre-hydroconversion fractionation to recover at least one or more pre-hydroconversion distillate(s), and a prehydroconversion fractionation bottom, so that only a fraction of the pre-hydroconversion effluent, preferably the pre-hydroconversion fractionation bottom, is incorporated in the hydrotreatment feed. These embodiments involve the additional benefit that the other fractions recovered from the pre-hydroconversion fractionation may be directed to other value-adding uses or processes. By suitably selecting the cut-point(s) in the prehydroconversion fractionation, an optimal utilisation and value addition of the renewable and / or circular content may be achieved.

[0016] Hence, in certain preferred embodiments, step a) comprises feeding the prehydroconversion effluent to a pre-hydroconversion fractionation to recover one or more prehydroconversion distillate(s) and a pre-hydroconversion fractionation bottom, combining a petroleum feed with the pre-hydroconversion fractionation bottom to obtain the hydrotreatment feed; the process further comprising: f) feeding the one or more pre-hydroconversion distillate(s) to a catalytic conversion, preferably to a catalytic conversion comprising at least hydroisomerisation, more preferably to a catalytic conversion comprising at least hydroprocessing and hydroisomerisation, optionally with at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste, to obtain a catalytic conversion effluent; and g) optionally recovering from the catalytic conversion effluent at least an aviation fuel component and / or a diesel fuel component. These embodiments involve the additional benefits that the conversion effluent may consist essentially of renewable and / or circular hydrocarbons, and the obtainable aviation and / or diesel fuel component(s) may have even very high isomerisation degree, and excellent cold-properties. According to a second example aspect, there is provided a naphtha fraction having a boiling point range within a range from IBP to 230°C (ASTM D7096-2019), preferably from 20°C to 220°C, and a difference between T90 and T10 temperatures (ASTM D7096-2019) within a range from 30 °C to 150 °C, preferably from 50 °C to 120 °C, and optionally a biogenic carbon content within a range from 1 to 50 wt.-%, preferably from 3 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the naphtha fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0017] According to a third example aspect, there is provided an aviation fuel range fraction having a boiling point range within a range from 120 °C to 310 °C (EN ISO 3405-2019), preferably from 130 °C to 300 °C, a difference between T90 and T10 temperatures (EN ISO 3405- 2019) within a range from 40 °C to 200 °C, preferably from 60 °C to 180 °C, and optionally a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 10 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the aviation fuel range fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0018] According to a fourth example aspect, there is provided a light gas oil fraction having a boiling point range within a range from 120°C to 330°C (EN ISO 3405-2019), preferably from 130°C to 320°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 190 °C, and optionally a biogenic carbon content within a range from 5 to 60 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the light gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0019] According to a fifth example aspect, there is provided a middle gas oil fraction having a boiling point range within a range from 190°C to 390°C (EN ISO 3405-2019), preferably from 200°C to 380°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 200 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the middle gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0020] According to a sixth example aspect, there is provided a heavy gas oil fraction having a boiling point range within a range from 270°C to 430°C (EN ISO 3405-2019), preferably from 280°C to 410°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 5 °C to 140 °C, preferably from 10 °C to 100 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the heavy gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0021] According to a seventh example aspect, there is provided a residual marine fuel component having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, and optionally a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 8 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the residual marine fuel component has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0022] Different non-binding example aspects and embodiments have been illustrated in the foregoing. The embodiments in the foregoing are used merely to explain selected aspects or steps that may be utilised in different implementations. Some embodiments may be presented only with reference to certain example aspects. It should be appreciated that corresponding embodiments may apply to other example aspects as well.

[0023] BRIEF DESCRIPTION OF THE FIGURES

[0024] Some example embodiments will be described with reference to the accompanying figure, in which:

[0025] Fig. 1 schematically shows a process according to an example embodiment of the present process. DETAILED DESCRIPTION

[0026] In the following description, like reference signs denote like elements or steps. All standards referred to herein are the latest revisions available at the filing date, unless otherwise mentioned.

[0027] Unless otherwise stated, regarding distillation characteristics, such as initial boiling points (IBP), final boiling points (FBP), T10 temperature (10 vol-% recovered), T90 temperature (90 vol-% recovered), and boiling point ranges (from IBP to FBP, unless otherwise specified), reference is made to EN ISO 3405-2019. IBP is the temperature at the instant the first drop of condensate falls from the lower end of the condenser tube, and FBP is the maximum thermometer reading obtained during the test, usually occurring after the evaporation of all liquid from the bottom of the flask. For boiling point distribution reference may also be made to GC-based method (simulated distillation) ASTM D2887-19e1 , or for gasoline range hydrocarbons to ASTM D7096-19.

[0028] As used in the context of this disclosure, aviation fuel range fraction or pool refers to hydrocarbon compositions suitable for use, at least as blend components, in fuels meeting standard specifications for aviation fuels, such as specifications laid down in ASTM D1655- 2023. Typically, such aviation fuel range fractions boil, i.e. have IBP and FBP, within a range from about 120 °C to about 310 °C, preferably within a range from about 130 °C to about 300 °C, as determined according to EN ISO 3405-2019.

[0029] As used in the context of this disclosure, diesel fuel range fraction or pool refers to hydrocarbon compositions suitable for use, at least as blend components, in fuels meeting standard specifications for diesel fuels, such as specifications laid down in EN 590:2022 or in EN 15940:2023. Typically, such diesel fuel range fractions boil, i.e. have IBP and FBP, within a range from about 130 °C to about 380 °C, such as within a range from about 160 °C to about 380 °C, as determined according to EN ISO 3405-2019. By temperate climate diesel fuel range fraction or pool (or fuel) reference is herein made to a diesel fuel range fraction or pool (or fuel) meeting one or more of the cold filter plugging point requirements (CFPP) laid down in EN 590:2022 Table 2, and by arctic and / or winter diesel fuel range fraction or pool (or fuel) reference is herein made to a diesel fuel range fraction or pool (or fuel) meeting one or more of the CFPP requirements and / or cloud point (CP) requirements laid down in EN 590:2022 Table 3 for arctic and severe winter climate diesels. As used in the context of this disclosure, gasoline fuel range fraction or pool, or naphtha fraction, refers to hydrocarbon compositions suitable - as such or after stabilisation - for use, at least as blend components, in fuels meeting standard specifications for gasoline fuels, such as specifications laid down in EN 228:2012 + A1 :2017. Typically, as stabilised, such gasoline fuel range or naphtha fractions boil, i.e. have IBP and FBP, within a range from about 20 °C to about 220 °C, preferably from about 25 °C to about 210 °C, as determined according to EN ISO 3405-2019. By light naphtha fraction reference is herein made to a fraction comprising C4 or heavier and having FBP at most about 180 °C, typically requiring stabilisation before use in gasoline fuels.

[0030] As used in the context of this disclosure, marine fuel range fraction or component refers to hydrocarbon compositions suitable for use, at least as blend components, in fuels meeting standard specifications for marine fuels, such as specifications laid down in ISO 8217-2017. Typically, such marine fuel range fractions or components boil, i.e. have IBP and FBP, within a range starting from about 180 °C or more, such as from about 180 °C to about 600 °C, as determined according to EN ISO 3405-2019. Marine fuel range components suitable for use in residual marine fuels (herein referred to as residual marine fuel components) may contain even very high boiling compounds, so instead of FBP, such marine fuel range components may be characterised by their kinematic viscosity (KV) at 50°C. Marine fuel range components suitable for use in residual marine fuels, i.e. residual marine fuel components, may have kinematic viscosity (KV) at 50°C for example at most 750 mm2 / s, or at most 700 mm2 / s, as determined according to EN ISO 3104-2020. Hence, hydrocarbons having IBP and KV at 50°C within these ranges may be regarded as suitable for use in marine fuels.

[0031] Regarding various fractionation methods and systems, involving e.g. distillation, it is to be understood that the fractionation precision may vary, and that in practice even consecutive fractions recovered from a separation stage may boil, i.e. have IBP and FBP, within partly overlapping ranges. Generally, any consecutive fractions have different T50 temperatures (EN ISO 3405-2019). More specifically, a fraction recovered from a separation stage may have a T60 temperature (EN ISO 3405-2019) that is lower than the T40 temperature (EN ISO 3405-2019) of the consecutive higher boiling fraction. Preferably a fraction recovered from a separation stage may have a T70 temperature (EN ISO 3405-2019) that is lower than the T30 temperature (EN ISO 3405-2019) of the consecutive higher boiling fraction.

[0032] As used herein, hydrocarbons refer to compounds consisting of carbon and hydrogen, including paraffins, n-paraffins, i-paraffins, monobranched i-paraffins, multibranched i- paraffins, olefins, naphthenes, and aromatics. Oxygenated hydrocarbons refer herein to hydrocarbons comprising covalently bound oxygen.

[0033] As used herein, paraffins refer to non-cyclic alkanes, i.e. non-cyclic, open chain saturated hydrocarbons that are linear (normal paraffins, n-paraffins) or branched (isoparaffins, i- paraffins). In other words, paraffins refer herein to n-paraffins and / or i-paraffins.

[0034] In the context of the present disclosure, i-paraffins refer to branched non-cyclic alkanes having one or more alkyl side chains. Herein, i-paraffins having one alkyl side chain or branch are referred to as monobranched i-paraffins and i-paraffins having two or more alkyl side chains or branches are herein referred to as multiple-branched i-paraffins. In other words, i-paraffins refer herein to monobranched i-paraffins and / or multiple-branched i- paraffins. The alkyl side chain(s) of i-paraffins may for example be C1 -C9 alkyl side chain(s), preferably methyl side chain(s). The amounts of monobranched and multiple-branched i- paraffins may be given separately. The term “i-paraffins” refers to sum amount of any monobranched i-paraffins and any multiple-branched i-paraffins, if present, indicating the total amount of any i-paraffins present regardless the number of branches. Correspondingly, “paraffins” refers to sum amount of any n-paraffins, any mono-branched, and any multiple- branched i-paraffins, if present.

[0035] In the context of the present disclosure, olefins refer to unsaturated, linear, branched, or cyclic hydrocarbons, excluding aromatic compounds. In other words, olefins refer to hydrocarbons having at least one unsaturated bond, excluding unsaturated bonds in aromatic rings.

[0036] As used herein, cyclic hydrocarbons refer to all hydrocarbons containing cyclic structure(s), including cyclic olefins, naphthenes, and aromatics. Naphthenes refer herein to cycloalkanes i.e. saturated hydrocarbons containing at least one cyclic structure, with or without side chains. As naphthenes are saturated compounds, they are compounds without aromatic ring structure(s) present. Aromatics refer herein to hydrocarbons containing at least one aromatic ring structure, i.e. cyclic structure having delocalized, alternating TT bonds all the way around said cyclic structure.

[0037] In the context of the present disclosure, for compositions boiling at <250°C (at standard atmospheric pressure), contents of n-paraffins, i-paraffins, monobranched i-paraffins, various multiple-branched i-paraffins, olefins, naphthenes, and aromatics are expressed as weight-% (wt-%) relative to the weight of the composition in question, or, when so defined, as weight-% (wt-%) relative to the (total) weight of paraffins, or (total) weight of i-paraffins of the composition in question. Said contents may be determined by GC-FID / GC-MS method, preferably conducted as follows: GC-FID as disclosed in ASTM D6839 was run using parameters: column ZB-1 60m, ID 0.25mm, df 1.0 microns, or similar; oven 0°C (2 min) - 1.5 °C / min 300 °C (5 min); injector and detector 300 °C; carrier gas helium 1.0 ml / min; detector gases H2 35 ml / min and air 350 ml / min; make up flow helium 30ml / min; split flow 165:1 (165 ml / min). Individual compounds were identified using GC-MS (run parameters: ion source 230°C; interface 280 °C; scan 25 - 280 m / z; scan speed 303; scan event time 0.88). Commercial tools (Shimadzu LabSolutions / GCMSSolutions and Agilent OpenLab) were used for identification of the detected compounds or hydrocarbon groups, and for determining their mass concentrations by application of response factors relative to n-heptane to the areas of detected peaks followed by normalization to 100 wt-% (for the liquid volume concentrations: by application of density factors to the calculated mass concentration of the detected peaks followed by normalization to 100 vol-%). Cyclic olefins are lumped with naphthenes. The limit of quantitation for individual compounds of this method is 0.1 wt-%.

[0038] Unless otherwise stated, in the context of the present disclosure, for compositions boiling at 36°C or higher at standard atmospheric pressure, contents of n-paraffins, i-paraffins, monobranched i-paraffins, multibranched i-paraffins, naphthenes, and aromatics are expressed as weight % (wt.-%) relative to the degassed weight of the composition in question, or, when so defined, as weight % (wt.-%) relative to the total weight of paraffins, or total weight of i-paraffins of the composition in question. Said contents may be determined by GCxGC-FID / GCxGC-MS method, preferably conducted as follows: GCxGC (2D GC) method was run as generally disclosed in UOP 990-2011 and by Nousiainen M. in the experimental section of his Master's Thesis Comprehensive two-dimensional gas chromatography with mass spectrometric and flame ionization detectors in petroleum chemistry, University of Helsinki, August 2017, with the following modifications. The GCxGC was run in reverse mode, using a semipolar column (Rxi17Sil) first and a non-polar column (Rxi5Sil) thereafter, followed by FID detector, using run parameters: carrier gas helium 31 .7 cm / s (column flow at 40 °C 1.60 ml / min); split ratio 1 :350; injector 280 °C; Column T program 40 °C (0 min) - 5 °C / min - 250 °C (0 min) - 10 °C / min - 300 30 °C (5 min), run time 52 min; modulation period 10 s; detector 300 °C with H2 40 ml / min and air 400 ml / min; makeup flow helium 30 ml / min; sampling rate 250 Hz and injection size 0.2 microliters. Individual compounds were identified using GCxGC-MS, with MS-parameters: ion source 230 °C; interface 300 °C; scan range 25 - 500 amu; event time (sec) 0.05; scan speed 20000. Commercial tools (Shimadzu's LabSolutions, Zoex's GC Image) were used for data processing including identification of the detected compounds or hydrocarbon groups, and for determining their mass concentrations by application of response factors relative to n- heptane to the volumes of detected peaks followed by normalization to 100 wt.-%. Olefins were lumped with naphthenes and heteroatomic species with aromatics, unless separately reported. The limit of quantitation for individual compounds of this method is 0.1 wt.-%.

[0039] Chemically, the renewable or non-renewable (such as petroleum) origin of any organic compound, including hydrocarbons, can be determined by suitable method for analysing the content of carbon from renewable sources e.g. DIN 51637:2014-02, ASTM D6866-2022, or EN 16640:2017. Said methods are based on the fact that carbon atoms of renewable or biological origin comprise a higher number of unstable radiocarbon (14C) atoms compared to carbon atoms of fossil origin. Therefore, it is possible to distinguish between carbon compounds derived from renewable or biological sources and carbon compounds derived from non-renewable (such as petroleum) sources by analysing the ratio of 12C and 14C isotopes. Thus, a particular ratio of said isotopes can be used as a “tag” to identify a renewable carbon compound and differentiate it from non-renewable carbon compounds. The isotope ratio does not change in the course of chemical reactions. Therefore, the isotope ratio can be used for identifying renewable carbon compounds and distinguishing them from non-renewable carbon compounds in feeds, (pre-)hydrotreatment feeds, cofeeds, fractions, or compositions, or various blends thereof. Numerically, the biogenic carbon content can be expressed as the amount of biogenic carbon in the material as a weight percent of the total carbon (TC) in the material (in accordance with ASTM D6866- 2022 or EN 16640:2017).

[0040] As used herein, the term circular in connection with content or materials such as (co-)feeds, fractions, or compositions refers to content or material that is based on or contains reused and / or recycled non-biogenic carbon, but that may additionally contain biogenic carbon. Typical exemplary sources for reused and / or recycled non-biogenic carbon, possibly also containing at least some biogenic carbon, include reclaimed organic commodities, especially waste plastics, end of life tires, used lubricants, and / or municipal solid waste.

[0041] Renewable, circular, and petroleum content, materials, (co-)feeds, fractions, or compositions are considered differing from one another based on their origin and impact on environmental issues. Therefore, they may be treated differently under legislation and regulatory framework. Typically, renewable, circular, and petroleum materials etc. are differentiated based on their origin and information thereof provided by the producer. In the context of this disclosure, CX hydrocarbons, paraffins, or similar, refer to hydrocarbons, paraffins, or similar, respectively, having a carbon number of at least X, where X is any feasible integer; CX-CY (or CX to CY) hydrocarbons, paraffins, or similar, refer to at least hydrocarbons, paraffins, or similar, respectively, having a carbon number of at least X and at most Y. It is understood that every compound having a carbon number falling within the definition is not necessarily present, and that also compounds having a carbon number falling outside the definition may be present.

[0042] By hydrotreatment, sometimes also referred to as hydroprocessing, is meant herein a catalytic process of treating organic material by means of molecular hydrogen. The hydrotreatment reactions may include removal of oxygen from oxygenated hydrocarbons as water i.e. hydrodeoxygenation (HDO), sulphur from organic sulphur compounds as dihydrogen sulphide (H2S), i.e. hydrodesulphurisation, (HDS), nitrogen from organic nitrogen compounds as ammonia (NH3), i.e. hydrodenitrogenation (HDN), halogens, for example chlorine from organic chloride compounds as hydrochloric acid (HCI), i.e. hydrodechlorination (HDCI), and / or metals by hydrodemetallization; and / or hydrogenation of olefinic bonds to saturated bonds and / or of aromatics to naphthenes. Depending e.g. on the composition of the hydrotreatment feed, different reactions may occur and / or prevail in the hydrotreatment. Generally, hydrotreatment is capable of converting hydrotreatment feeds of varying compositions to more pure materials, by reducing content of heteroatoms, metals, olefins, aromatics and / or other less desired compounds in the hydrotreatment feed. Hydrotreatment may also involve certain side reactions, such as hydrocracking reactions, that may actually be beneficial in the (pre-)hydrotreatment of the present process.

[0043] By hydrocracking is meant herein a catalytic process of treating organic material in the presence of molecular hydrogen, causing the feed molecules to crack into smaller, lower- boiling compounds. The presence of hydrogen ensures reduced olefin formation. Hydrocracking may also involve ring-opening of cyclic feed components, as well as cleavage of heteroatoms. Depending on the feed composition, hydrocracking conditions and the used catalyst, isomerisation reactions may also occur during hydrocracking. Unlike for hydrotreatment catalysts, at least some acidity is required for a hydrocracking catalyst, which may be attained e.g. by using acidic materials and / or incorporating promoters such as certain metals, as is well known in the art.

[0044] As used herein, wherever the reaction steps are defined to take place in “reactors”, such as the hydrotreatment reactor and hydrocracking reactor, said expression is used for illustrative purposes mainly. A person skilled in the art contemplates that any “reactor” is in practice implemented as a reactor system that may consist of one or more reactors. Whether the reactors are actually arranged in a single reactor or several reactors is a matter of engineering, and may be influenced by practical issues such as maximum height of the facility at the site, reactor diameter, regulatory and maintenance issues at the site, wind conditions at the site, and / or available equipment. Analogously, the “separation” or “separation stage” may take place in a separation system, typically comprising e.g. separators and distillation units, which may be arranged according to conventional engineering practice in the field.

[0045] Regarding various separation and / or fractionation methods and systems, involving e.g. distillation, it is to be understood that the separation and / or fractionation precision may vary, and that in practice even consecutive liquid fractions recovered from a separation stage may boil, i.e. have IBP and FBP, within partly overlapping ranges. Generally, any consecutive liquid fractions have different T50 temperatures. More specifically, a liquid fraction recovered from a separation stage may have a T60 temperature that is lower than the T40 temperature of the consecutive higher boiling fraction. Preferably a liquid fraction recovered from a separation stage may have a T70 temperature that is lower than the T30 temperature of the consecutive higher boiling fraction.

[0046] The present disclosure provides a process for producing hydrocarbon fractions, the process comprising: a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste to a pre-hydroconversion in a pre-hydroconversion reactor in the presence of a pre-hydroconversion catalyst to obtain a pre-hydroconversion effluent, and co-feeding a petroleum feed to the pre-hydroconversion reactor and / or combining a petroleum feed with at least a fraction of the prehydroconversion effluent, to obtain a hydrotreatment feed having petroleum content as well as renewable and / or circular content, b) subjecting the hydrotreatment feed to hydrotreatment in a hydrotreatment reactor in the presence of a hydrotreatment catalyst to obtain a hydrotreatment effluent, c) introducing at least a portion of the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least three different distillates, and a separation stage bottom having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, d) recovering a residual marine fuel component from the separation stage bottom, preferably by splitting a portion from the separation stage bottom, e) subjecting a hydrocracking feed comprising a portion of the separation stage bottom to hydrocracking in a hydrocracking reactor in the presence of a hydrocracking catalyst to obtain a hydrocracking effluent, and co-feeding at least a portion of the hydrocracking effluent with the hydrotreatment effluent to the separation stage.

[0047] The present process allows to produce several hydrocarbon fractions with renewable and / or circular content, in good yields and quality e.g. for use in fuel compositions. The process improves the overall economy of the process and provides improved flexibility and higher overall value of the product slate. At the same time GHG emissions and dependence from the diminishing petroleum sources is reduced. The advantages relate to a finding that with the pre-hydroconversion step, renewable and / or circular content may be introduced in the hydrotreatment feed virtually without restrictions, especially in view of hydrotreatment reactor exotherm and / or corrosion risk mitigation, and said content may be further spread over a wider boiling range with the subsequent hydrotreatment and hydrocracking steps, enabling recovery of several product fractions with significant renewable and / or circular content. Also flexibility regarding choice of the renewable and / or circular feeds is enhanced, allowing even highly challenging renewable and / or circular feeds to be introduced, as prehydroconverted, into conventional petroleum refinery units.

[0048] In the present process renewable and / or circular content is incorporated in the hydrotreatment feed. The renewable and / or circular content in the hydrotreatment feed originates from renewable and / or circular feed(s), i.e. at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and / or liquefied organic waste, subjected to the pre-hydroconversion. Typical vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and / or liquefied organic waste may contain for example fatty acid(s), fatty acid glyceride(s), fatty acid alkyl ester(s), fatty alcohol(s), resin acid(s), resin ester(s), other oxygenated hydrocarbons, olefins, and / or cyclic hydrocarbons. Exemplary vegetable oil(s) usable in the present process include rapeseed oil, canola oil, soybean oil, coconut oil, sunflower oil, palm oil, palm kernel oil, peanut oil, linseed oil, sesame oil, maize oil, poppy seed oil, cottonseed oil, soy oil, tall oil, crude tall oil (CTO), corn oil, castor oil, jatropha oil, jojoba oil, olive oil, flaxseed oil, camelina oil, safflower oil, babassu oil, seed oil of any of Brassica species or subspecies, such as Brassica carinata seed oil, Brassica juncea seed oil, Brassica oleracea seed oil, Brassica nigra seed oil, Brassica napus seed oil, Brassica rapa seed oil, Brassica hirta seed oil and Brassica alba seed oil, and rice bran oil, and / or fractions or residues of said vegetable oils such as palm olein, palm stearin, palm fatty acid distillate (PFAD), purified tall oil, tall oil fatty acids, tall oil resin acids, distilled tall oil, tall oil unsaponifiables, tall oil pitch (TOP), and / or used cooking oils of vegetable origin; exemplary animal fats may include tallow, lard, yellow grease, brown grease, fish fat, poultry fat, and / or used cooking oil of animal origin; and exemplary microbial oils may include algal lipids, fungal lipids, and / or bacterial lipids. The lignocellulose-derived biocrude(s) may comprise thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied lignocellulosics, wherein exemplary lignocellulosics may include woody biomass and residues such as wood chips, sawdust, forestry thinnings, road cuttings, bark, branches, garden and park wastes and weeds, energy crops like coppice, willow, miscanthus, and giant reed; agricultural (by)products such as grasses, straw, stems, stover, husk, cobs and shells from e.g. wheat, rye, corn rice and / or sunflowers, empty fruit bunches from palm oil production, palm oil manufacturers effluent, residues from sugar production such as bagasse, vinasses, molasses and / or greenhouse wastes, energy crops like miscanthus, switchgrass, sorghum, and / or jatropha; and / or lignocellulosic industrial waste streams such as paper sludges, off- specification fibres from paper production, residues and byproducts from food production such as juice or wine production, vegetable oil production, restaurant wastes. The liquefied organic waste may comprise thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied organic waste. The organic waste may comprise waste plastics, end of life tires (ELT), used lubricants, and / or municipal solid waste (MSW). Evidently, due to its mixed waste nature, the liquefied organic waste has non- biogenic carbon content, and typically also biogenic carbon content. For example the biogenic carbon content of MSW may vary greatly, but is typically significant, such as from 40 to 70 wt.-%, based on the total weight of carbon (TC) in the MSW, due to biomass-waste present in MSW. Also the biogenic carbon content of ELT may vary, but is typically significant, such as from 15 to 40 wt.-%, based on the total weight of carbon (TC) in the ELT, due to e.g. natural rubber present in ELT. Also the biogenic carbon content of liquefied waste plastics may vary, but is currently foreseen much lower than the share of non- biogenic carbon content, due to the low share of bio-based plastics in the waste plastics, however this may change over time when the production of bio-based plastics increases.

[0049] The renewable and / or circular feeds exemplified in the foregoing are readily available in quantities and qualities usable in the present process, and various established pretreatment techniques exist for purifying these materials. If the at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste contains amounts or species of impurities that are not tolerated or preferred in the pre-hydroconversion, the content of said impurities may be reduced to acceptable limits using pre-treatment methods known in the art. Exemplary pre-treatment methods suitable for the present disclosure comprise treating with mineral acids, degumming, treating with hydrogen, heat treating, deodorizing, washing with water, treating with base, demetallation, distillation, removal of solids, bleaching, and any combinations thereof.

[0050] Vegetable oil(s), animal fat(s), microbial oil(s), and lignocellulose-derived biocrude(s) are essentially biogenic, and may hence be preferred feeds in step a). On the other hand, typical fatty materials such as vegetable oil(s), animal fat(s), and / or microbial oil(s), as well as liquefied organic waste tend to form paraffins upon the pre-hydroconversion and / or the hydrotreatment, whereof well over 50 wt.-% may be n-paraffins, that are excellent cetane enhancers. Paraffins are also easier to crack compared to cyclic hydrocarbons that may be abundant e.g. in lignocellulose-derived biocrude(s). Vegetable oil(s), animal fat(s), and / or microbial oil(s) may be regarded as further preferred feeds in step a), due to the renewable propane formed from the glycerol backbone typically present in these lipidic materials. The formed propane may be separated from the pre-hydroconversion effluent and utilised e.g. as purified for production of renewable propylene, or among other light hydrocarbons for production of renewable hydrogen in a hydrogen production unit. Hence, in certain preferred embodiments the process comprises a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), and / or liquefied organic waste, preferably at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s), to the pre-hydroconversion.

[0051] The petroleum content of the hydrotreatment feed may vary within broad ranges, such as from 1 to 99 wt.-%. In certain preferred embodiments, the hydrotreatment feed has a petroleum content within a range from 5 to 95 wt.-%, preferably from 10 to 95 wt.-%, more preferably from 15 to 90 wt.-%, even more preferably from 20 to 85 wt.-%. By using a prehydroconverted renewable and / or circular feed, the petroleum content may be kept very low without significant corrosion concerns regarding metallurgy of the hydrotreatment reactor, and also varied flexibly within broad ranges depending e.g. on fluctuations in the availability and / or quality of the renewable and / or circular feed(s). By incorporating petroleum content in the hydrotreatment feed, the hydrotreatment catalyst may remain sufficiently sulphided and hence active even without separate sulphur spiking. Petroleum contains various hydrocarbons of the paraffinic, naphthenic, and aromatic compound classes, and with a very broad molecular weight range. Hence, certain petroleum content may be regarded as beneficial also for product property reasons, e.g. providing cyclic compounds to the gasoline fuel range fraction(s) thereby improving octane rating.

[0052] Additionally, as the renewable and / or circular content is introduced in the hydrotreatment feed as pre-hydroconverted, the efficiency of the hydrotreatment step e.g. to reduce heteroatom content, saturate olefins and dearomatize is not compromised. The hydrotreatment efficiency may even increase compared to an otherwise similar process but utilising 100% petroleum feed, and / or petroleum co-feeds of lower quality could be used.

[0053] Typically, the petroleum feed comprises more than 30 wt.-%, preferably more than 40 wt.- %, more preferably more than 50 wt.-% of hydrocarbons boiling within a range from 100 °C to 400 °C (ASTM D2887-2023), and more than 10 wt.-%, preferably at least 20 wt.-%, more preferably at least 30 wt.-%, of hydrocarbons boiling above 380°C (ASTM D2887-2023), based on the total petroleum feed weight. The choice of the petroleum feed is not particularly limited, but components of lesser quality and / or having limited utility in high value applications may be preferred e.g. over straight-run petroleum distillates. In this way, the overall value of a product slate of an entire petroleum refinery may be optimised. Hence, in certain preferred embodiments, the petroleum feed comprises at least one or more of atmospheric distillation bottom(s); vacuum distillate(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric distillation bottom(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked vacuum distillate(s); and / or atmospheric bottom(s) of (hydro)cracked vacuum distillate(s), of a petroleum crude oil. In embodiments where petroleum feed is co-fed at several locations, such as to two or more of the pre-hydroconversion reactor, pre-hydroconversion fractionation and hydrotreatment reactor, different petroleum feed qualities may be co-fed at different locations. For example, a petroleum feed fed to the pre-hydroconversion reactor may contain other and even heavier materials than exemplified above, such as crude oil vacuum distillate, and / or vacuum distillation bottom preferably as deasphalted, while a petroleum feed fed to the hydrotreatment reactor is preferably as exemplified above. To further increase the sustainable content in the hydrotreatment feed, also further renewable and / or circular feed may be co-fed to the hydrotreatment reactor, as pre-hydroconverted and / or minor amounts even without pre-hydroconversion.

[0054] In certain preferred embodiments, step a) comprises subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and / or liquefied organic waste to a pre-hydroconversion in a pre-hydroconversion reactor in the presence of a pre-hydroconversion catalyst to obtain a pre-hydroconversion effluent, and combining a petroleum feed with at least a fraction of the pre-hydroconversion effluent, to obtain a hydrotreatment feed having petroleum content as well as renewable and / or circular content. In the absence of petroleum feed in the pre-hydroconversion step, sulphur may be present only in limited amounts, e.g. only to keep the pre-hydroconversion catalyst sulphided and active. The entire pre-hydroconversion capacity and the pre-hydroconversion conditions may be optimised for processing the renewable and / or circular content, without being consumed e.g. by HDS reactions required for the fossil feeds.

[0055] Generally, when the hydrotreatment feed has renewable content, i.e. contains biogenic carbon, particularly at least one or more of an aviation fuel range fraction, a light gas oil fraction, a middle gas oil fraction, and / or a heavy gas oil fraction recovered from the separation stage may have a biogenic carbon content (EN 16640:2017) that is higher than the biogenic carbon content of the hydrotreatment feed. The biogenic carbon content in the recovered fraction(s) is influenced by the biogenic carbon content in the hydrotreatment feed, by the selection of the cut-point values in the separation stage, and by the selection of the cut-point value(s) in the pre-hydroconversion fractionation. Similar considerations apply to the circular carbon content, for which however no analysis method exists.

[0056] In certain preferred embodiments, in step a) at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), and / or lignocellulose-derived biocrude(s), preferably at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s), is / are subjected to the prehydroconversion, and the petroleum feed and the at least a fraction of the prehydroconversion effluent are incorporated in the hydrotreatment feed in a weight-ratio within a range from 5:95 to 95:5, preferably from 10:90 to 95:5, more preferably from 15:85 to 90:10, even more preferably from 20:80 to 85:15; and wherein each of the at least three different distillates recovered in step c) and the residual marine fuel component recovered in step d) has a biogenic carbon content (EN 16640:2017). Typically in these embodiments, each of the at least three different distillates recovered in step c) and the residual marine fuel component recovered in step d) has a biogenic carbon content within a range from 1 .5 to 99.0 wt.-%, preferably from 3.0 to 95.0 wt.-%, more preferably from 5.0 to 90.0 wt.-%, based on the total weight of carbon (TC) in the distillate / component (EN 16640:2017).

[0057] The present process involves a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste to a pre-hydroconversion in a pre-hydroconversion reactor in the presence of a prehydroconversion catalyst to obtain a pre-hydroconversion effluent. The pre- hydroconversion is conducted in the presence of added hydrogen. Preferably the prehydroconversion comprises pre-hydrotreating and / or pre-hydrocracking, more preferably at least pre-hydrotreating, in the pre-hydroconversion reactor in the presence of a prehydrotreatment and / or pre-hydrocracking catalyst(s), preferably at least pre-hydrotreatment catalyst, to obtain the pre-hydroconversion effluent. Pre-hydrotreating is preferred especially to reduce heteroatom content, while benefits of pre-hydrocracking include spreading the sustainable content over a broader boiling range, thereby more efficiently ending-up in each of the recovered product fractions.

[0058] The pre-hydrocracking may be carried out as described in the following for the hydrocracking. The pre-hydrotreating may be carried out as described in the following for the hydrotreatment, or at somewhat milder conditions. Hence, in certain preferred embodiments, the pre-hydroconversion comprises pre-hydrotreating in the prehydroconversion reactor, wherein the pre-hydrotreating is be conducted at a temperature within a range from 300 °C to 420 °C, preferably from 320 °C to 380 °C, a pressure within a range from 3 MPa to 15 MPa, preferably from 4 MPa to 10 MPa, a H2 partial pressure at the inlet of the pre-hydroconversion reactor within a range from 3 MPa to 15 MPa, preferably from 4 MPa to 10 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg pre-hydroconversion feed per kg catalyst per hour, and a H2 to pre-hydroconversion feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter pre-hydroconversion feed, in the presence of a pre-hydrotreatment catalyst. In certain embodiments the pre-hydrocracking is conducted in one or more ebullated catalyst bed(s). In these embodiments the temperature and / or pressure may be as discussed above, or even somewhat higher.

[0059] Selecting the pressure and / or the temperature in the pre-hydroconversion so that the pressure is at a higher side and / or the temperature is at a lower side, deoxygenation via decarboxylation / decarbonylation reactions may be further suppressed, thereby controlling formation of carbon oxides and their content in the gaseous phase of the prehydroconversion effluent.

[0060] The pre-hydrotreatment catalyst may be any conventional hydrotreatment catalyst well known in the art, such as any of those described in the following for the hydrotreatment catalyst. The pre-hydrocracking catalyst may be any conventional hydrocracking catalyst well known in the art, such as any of those described in the following for the hydrocracking catalyst. Preferably a sulphided pre-hydroconversion catalyst is used. By incorporating petroleum content in the pre-hydroconversion feed, the pre-hydroconversion catalyst, including pre-hydrotreatment and / or pre-hydrocracking catalyst(s), may remain sufficiently sulphided and hence sufficiently active even without separate sulphur spiking. Alternatively or additionally, the pre-hydroconversion feed may be spiked with additional sulphur to maintain the catalyst sufficiently sulphided and active.

[0061] By pre-hydroconverting, particularly pre-hydrotreating and / or pre-hydrocracking, the renewable and / or circular feed(s), formation of carbon dioxide and carbon monoxide in the hydrotreatment step b) may be minimised or even eliminated. While CO2 may be efficiently removed from reactor effluent’s gaseous phase using conventional purification technologies, such as sweetening removing both H2S and CO2, CO may accumulate in the recycle hydrogen stream that may be recovered from the gaseous stream separated from pre-hydroconversion effluent, thereby limiting e.g. how much of the recycle hydrogen stream could actually be recycled back to refinery’s various hydrotreatment and / or hydrocracking units. By subjecting the renewable and / or circular feed(s) to prehydroconversion, the conditions in the pre-hydroconversion reactor may be optimised to favour hydrodeoxygenation reactions over decarboxylation / decarbonylation reactions e.g. by limiting presence of sulphur compounds, limiting the temperature and / or increasing the pressure in the pre-hydroconversion reactor. Using a separate pre-hydroconversion step also allows a gaseous stream separated from the pre-hydroconversion effluent to be specifically processed so as to mitigate issues relating to CO accumulation in a recycle hydrogen stream recovered from the gaseous stream.

[0062] The optional pre-hydroconversion fractionation of the pre-hydroconversion effluent may comprise any conventionally used fractionation technology, and may be arranged similarly as described in the following in connection with the separation stage. However, since only the renewable and / or circular content to be incorporated in the hydrotreatment feed needs to be subjected to the pre-hydroconversion, the pre-hydroconversion fractionation may be smaller and / or simpler, hence involving lower investment and operating costs. In certain embodiments, mere gas-liquid separation and optionally stabilisation may suffice for the pre-hydroconversion effluent, thereby further reducing the investment and operating costs of the pre-hydroconversion fractionation, and maximising yield of the renewable and / or circular molecules to be subjected to the hydrotreatment.

[0063] In certain preferred embodiments, the pre-hydroconversion effluent is fed to a prehydroconversion fractionation to recover at least one or more pre-hydroconversion distillate(s), and a pre-hydroconversion fractionation bottom, so that only a fraction of the pre-hydroconversion effluent, preferably the pre-hydroconversion fractionation bottom, may be incorporated in the hydrotreatment feed. These embodiments involve the additional benefit that the other fractions recovered from the pre-hydroconversion fractionation may be directed to other value-adding uses or processes. By suitably selecting the cut-point(s) in the pre-hydroconversion fractionation, an optimal utilisation and value addition of the renewable and / or circular content may be achieved.

[0064] In certain preferred embodiments, step a) comprises feeding the pre-hydroconversion effluent to a pre-hydroconversion fractionation to recover one or more pre-hydroconversion distillate(s) and a pre-hydroconversion fractionation bottom, combining a petroleum feed with the pre-hydroconversion fractionation bottom to obtain the hydrotreatment feed; the process further comprising: f) feeding the one or more pre-hydroconversion distillate(s) to a catalytic conversion, preferably to a catalytic conversion comprising at least hydroisomerisation, more preferably to a catalytic conversion comprising at least hydroprocessing and hydroisomerisation, optionally with at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste, to obtain a catalytic conversion effluent; and g) optionally recovering from the catalytic conversion effluent at least an aviation fuel component and / or a diesel fuel component. Due to the removal of the pre-hydroconversion fractionation bottom containing the heaviest compounds, processing of the prehydroconversion distillate(s) in a subsequent catalytic conversion may be easier, involving e.g. reduced risk of dusting in catalyst beds and / or pressure drop over fixed catalyst beds. Additionally the pre-hydroconversion distillate(s) are good diluents for oxygenated hydrocarbons in hydroprocessing, and help to control the hydroprocessing exotherm and / or corrosion risk. The embodiments involving hydroisomerisation allow recovery of an aviation fuel component and / or a diesel fuel component having high isomerisation degree, when desired e.g. due to increased market demand at a given time. The achieved high isomerisation degree is foreseen to improve cold properties, fluidity, pumping and mixing characteristics and blendability of the recovered components and / or products. These are generally desired and beneficial properties without limitation to fuel purposes but for a wide range of uses, particularly involving spraying, injecting and / or admixing with other ingredients.

[0065] In certain further preferred embodiments, step a) comprises subjecting at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s) to the pre-hydroconversion, and feeding the pre-hydroconversion effluent to a pre-hydroconversion fractionation to recover one or more pre-hydroconversion distillate(s) and a pre-hydroconversion fractionation bottom, combining a petroleum feed with the pre-hydroconversion fractionation bottom to obtain the hydrotreatment feed; and f) feeding the one or more pre-hydroconversion distillate(s) to a catalytic conversion, preferably to a catalytic conversion comprising at least hydroisomerisation, more preferably to a catalytic conversion comprising at least hydroprocessing and hydroisomerisation, optionally with at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s), to obtain a catalytic conversion effluent; and g) optionally recovering from the catalytic conversion effluent at least an aviation fuel component and / or a diesel fuel component. These embodiments involve the further benefit of providing some products with 100 wt.-% biogenic carbon content, with concomitant formation of renewable propane from the glycerol backbone typically present in these lipidic materials. The formed propane may be separated and utilised e.g. for production of renewable propylene, or for production of renewable hydrogen in a hydrogen production unit. In these embodiments, the hydroprocessing may be conducted e.g. as described in the following for the hydrotreatment or in the foregoing for the pre-hydrotreating, and the hydroisomerisation may be conducted e.g. as described in FI100248B, EP1741768A1 , EP1741768A1 , EP2155838B1 , FI129220B1 , EP1396531A2, or EP0985010A1 .

[0066] The hydrotreatment is conducted in the presence of added hydrogen. The hydrotreatment may be conducted e.g. using any hydrotreatment reactor(s), conditions and catalyst(s) known by a skilled person and / or conventionally used e.g. in petroleum refineries. The hydrotreatment in the hydrotreatment reactor may for example be conducted at a temperature within a range from 300 °C to 450 °C, preferably from 350 °C to 420 °C, a pressure within a range from 6 MPa to 20 MPa, preferably from 10 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrotreatment reactor within a range from 6 MPa to 20 MPa, preferably from 10 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrotreatment feed per kg catalyst per hour, and a H2 to hydrotreatment feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter hydrotreatment feed, in the presence of a hydrotreatment catalyst. Within these conditions the efficiency of the hydrotreatment step in terms of selectivity and / or activity regarding hydrotreatment reactions, including heteroatom content reduction, olefins saturation and dearomatization, may be further enhanced, hydrotreatment catalyst deactivation controlled, and undesired side reactions suppressed. For example, the relatively high hydrogen pressure in the hydrotreatment helps to minimise presence and formation of olefins, thereby contributing i.a. to improved stability of the product fractions The hydrotreatment catalyst may be any conventionally used hydrotreatment catalyst or combination thereof, no special catalysts are needed. Exemplary hydrotreatment catalysts include those described in various handbooks in the field, such as in Handbook of Petroleum Processing, Springer 2006, edited by Jones and Pujado, Chapter s Hydrotreating, Catalysts p. 334-344; in Petroleum Refining, Vol 3 Conversion Processes, Editions Technip 2001 , edited by P. Leprince, Chapter 16 Hydrotreating p. 546-549; and in Handbook of Petroleum Refining, CRC Press 2017, edited by James G. Speight, Chapter 10 Hydrotreating processes p. 423-424; or in patent publications, especially in FI100248B, EP1741768A1 , EP2155838B1 or FI129220B1. Hence, in certain embodiments the hydrotreatment catalyst comprises at least one or more metals from Group VIII of the Periodic Table and / or from Group VI B of the Periodic Table, preferably at least one or more of Ni, Mo, W, and / or Co, even more preferably at least one or more of Ni and / or Co and Mo and / or W, such as NiMo, CoMo, NiCoMo, NiW, and / or NiMoW, preferably on a support such as alumina and / or silica, more preferably gamma-alumina, optionally additized with minor amounts of silica or phosphorous. These hydrotreatment catalysts are efficient, readily available, commonly used e.g. for HDS of petroleum feeds and are usable also for HDO of e.g. fatty feeds, and tolerate typical impurities of the hydrotreatment feed used in the present process well.

[0067] Also catalyst(s) containing acidic porous material(s), especially zeolite(s) and / or zeolitetype material(s), having suitable shape-selective framework type, and optionally also metal sites for catalysing (de)hydrogenation reactions, e.g. as described in Handbook of Petroleum Refining, CRC Press 2017, edited by James G. Speight, Chapter 12.3.5 Catalytic Dewaxing Process p. 548-550, may be utilised as hydrotreatment co-catalysts, at least in one catalyst bed in the hydrotreatment reactor, so as to reduce content of long n-paraffins and to increase content of isoparaffins and / or cracked paraffins in the hydrotreatment effluent. These catalysts are herein referred to as dewaxing catalysts. Hence, in certain preferred embodiments, in step b) the hydrotreatment reactor further contains a dewaxing catalyst, to obtain the hydrotreatment effluent.

[0068] The separation stage of the present process may utilise any conventional separation and / or fractionation technology. The separation stage may be carried out in a separation stage system comprising one or more separation and / or fractionation units. For example, at least part of the gases may be separated in a gas-liquid separation e.g. as described hereinafter. Thereafter, another separation and / or fractionation unit, such as a stabilisation unit, may be utilised to further separate at least a portion of remaining gases, such as fuel gases, and e.g. a light naphtha fraction. Stabilisation, i.e. one type of partial distillation for removing gaseous and most volatile liquid hydrocarbons to reduce vapour pressure may be conducted for example using a stripper or a distillation column, while fractionation may be conducted for example using e.g. a distillation column. Further distillates such as a heavy naphtha fraction, an aviation fuel range fraction, a light gas oil fraction, a middle gas oil fraction and / or a heavy gas oil fraction, and a separation stage bottom may be recovered e.g. using one or more distillation unit(s). The distillation unit(s) may comprise atmospheric distillation and / or vacuum distillation unit(s). In an alternative example, a single fractionation unit may be used.

[0069] As mentioned, the hydrotreatment effluent, but also the pre-hydroconversion effluent and / or the hydrocracking effluent, may be subjected to gas-liquid separation. The gas-liquid separation of the hydrotreatment effluent, the pre-hydroconversion effluent, and / or the hydrocracking effluent may be conducted for example as an integral step within the respective reactor, or subsequently e.g. using high pressure-high temperature, high pressure-medium temperature or similar separator(s). Typically, the gas-liquid separation is conducted at a temperature within a range from 0 °C to 500 °C, such as from 15°C to 300°C, or from 15 °C to 150 °C, preferably from 15 °C to 65 °C, such as from 20 °C to 60 °C, and preferably at essentially same pressure as that of the reactor wherefrom the effluent originates. Typically, the pressure during the gas-liquid separation(s) may be within a range from 0.1 MPa to 20 MPa, preferably from 1 MPa to 18 MPa, or from 3 MPa to 15 MPa. The gas-liquid separation allows to recover compounds that are gaseous under the separation conditions (herein referred to as a gaseous stream) from the respective reactor effluent.

[0070] Exemplary compounds retained in a gaseous stream separated from the respective reactor effluent may include at least one or more of residual hydrogen, hydrogen disulphide, ammonia, and / or light hydrocarbons. Even some carbon monoxide, carbon dioxide and / or water may be present, although these are more abundant in a gaseous stream optionally separated from the pre-hydroconversion effluent. The separated gaseous stream(s) may be subjected to conventional treatments, depending on the composition of the gaseous stream, such as sweetening, recovery of recycle hydrogen stream, and / or recovery of light hydrocarbons. Light hydrocarbons, such as C1-C3 hydrocarbons, as optionally recovered e.g. from the gaseous stream(s), from steam stripper and / or distillation tower overhead(s), and / or from stabilisation of any of the distillates, are herein collectively referred to as fuel gases. Light naphtha fraction, on the other hand, may contain at least hydrocarbons that are heavier than the fuel gases and that may be recovered e.g. from steam stripper and / or distillation tower overhead(s), and / or from stabilisation of any of the distillates. In certain preferred embodiments, a recycle hydrogen stream, fuel gases and / or a light naphtha fraction is / are further recovered from the separation stage, and at least a portion of the fuel gases and / or a light naphtha fraction is fed to a hydrogen production unit, preferably to a steam reforming unit, to obtain a syngas, followed by recovering a make-up hydrogen stream from the syngas; and optionally at least a portion of the recycle hydrogen stream and / or the make-up hydrogen stream is recycled to the pre-hydroconversion in step a), to the hydrotreatment in step b), and / or to the hydrocracking in step e). Utilising such recycle hydrogen stream and / or make-up hydrogen stream in the present process enhances economy thereof.

[0071] The present process also involves a hydrocracking step, converting the separation stage bottom to shorter hydrocarbons, thereby further increasing the yield of the distillates and further spreading the renewable and / or circular content over a wider boiling range. By subjecting to the hydrocracking only the separation stage bottom, the vapour load is reduced so that a smaller equipment may suffice, or a higher (full) capacity is available in the hydrocracking step for converting the heavy molecules. The reduced vapour load enhances hydrogen purity and allows a higher hydrogen partial pressure in the hydrocracking step, even towards the end of the reactor, despite the significant hydrogen consumption and the formed gaseous cracking products reducing the H2 partial pressure. In this way residual olefins and heteroatoms are minimised and catalytic reactions enhanced so that the recovered fractions are purer and more stable

[0072] The hydrocracking is conducted in the presence of added hydrogen. The hydrocracking may be conducted e.g. using any hydrocracking reactor(s), conditions and catalyst(s) known by a skilled person and / or conventionally used e.g. in petroleum refineries. The hydrocracking in the hydrocracking reactor may be conducted at a temperature within a range from 280 °C to 450 °C, preferably from 300 °C to 420 °C, a pressure within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrocracking reactor within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrocracking feed per kg catalyst per hour, and a H2 to hydrocracking feed ratio within a range from 50 to 2000, preferably from 500 to 1500 normal liters H2 per liter hydrocracking feed, in the presence of a hydrocracking catalyst. Within these conditions the efficiency of the hydrocracking step in terms of selectivity and / or activity regarding hydrocracking reactions may be further enhanced, hydrocracking catalyst deactivation controlled, undesired side reactions suppressed and desired conversion level reached. For example, the relatively high hydrogen pressure in the hydrocracking helps to minimise presence and / or formation of olefins, thereby contributing i.a. to improved stability of the product fractions. The hydrocracking catalyst may be any conventionally used hydrocracking catalyst or combination thereof, no special catalysts are needed. For example, any bifunctional hydrocracking catalysts comprising metal sites for catalysing (de)hydrogenation reactions and acid sites for catalysing cracking reactions known in the field of oil refining and in the field of renewable fuel production may be utilised. Typical hydrocracking catalysts contain elemental noble metals such as platinum and / or palladium, or sulfided base metals such as nickel, cobalt, tungsten and / or molybdenum; an acidic porous material, typically zeolites and / or zeolite-type materials showing high cracking activity and having a suitable framework type, or an amorphous silica-alumina; and optionally also a refractory support such as alumina, silica and / or titania. The hydrocracking catalysts may also comprise further components, such as boron or phosphorous. Exemplary hydrocracking catalysts for use in the present process include those described e.g. in Handbook of Petroleum Refining, CRC Press 2017, edited by James G. Speight, Chapter 11 Hydrocracking p. 423-424; or in patent publications, especially in W02020083989 or WO2011007046. Hence, in certain embodiments the hydrocracking catalyst is a bifunctional hydrocracking catalyst, preferably a non-sulphided bifunctional hydrocracking catalyst, comprising at least one or more metals selected from Ni, Mo, Co, W, Pt and / or Pd, more preferably from Pt and / or Pd; and at least one or more acidic porous materials selected from zeolites, zeolite-type materials and / or amorphous silica-alumina, wherein preferably at least one or more of the zeolites or zeolitetype materials has a framework type selected from MFI, BEA, FAll, AFI, ATO, AFO, MTT, and / or TON, preferably at least one or more acidic porous materials selected from SAPO- 5, SAPO-31 , SAPO-41 , ZSM-22, ZSM-23, ZSM-5, beta-zeolites, Y-type zeolites, and / or amorphous silica-alumina; and optionally at least one or more of alumina, silica, and / or titania. Non-sulphided, noble-metal hydrocracking catalysts are active at lower temperatures. As the hydrotreatment in step b) cleaves efficiently S and N bound in the feed molecules forming H2S and NH3 gases, and only the separation stage bottom (part thereof) continues to the hydrocracking, rapid deactivation of the noble metal hydrocracking catalyst is not a concern.

[0073] Hydroisomerisation catalyst(s) may be utilised as co-catalysts in hydrocracking in step e), at least in one catalyst bed in the hydrocracking reactor, so as to reduce content of n- paraffins and to increase content of isoparaffins in the hydrocracking effluent, thereby improving cold properties of the product fractions. Hence, in certain preferred embodiments, in step e) the hydrocracking reactor further comprises a hydroisomerisation catalyst. Any bifunctional hydroisomerisation catalysts comprising metal sites for catalysing (de)hydrogenation reactions and acid sites for catalysing isomerisation reactions known in the field of oil refining and in the field of renewable fuel production may be utilised, for example hydroisomerisation catalyst(s) described in FI100248B, EP1741768A1 , EP1741768A1 , EP2155838B1 , FI129220B1 , EP1396531A2, or EP0985010A1 , preferably non-sulphided, noble-metal hydroisomerisation catalyst(s).

[0074] The advantages of the present process may be attained with reduced costs, especially when utilising existing assets of a petroleum refinery. The present process is well suited for running in conventional or existing petroleum refinery units. Only the pre-hydroconversion reactor may need to be made of higher metallurgy grade than conventional petroleum refinery units. Hence, in certain preferred embodiments, at least one or more, preferably at least two or more, more preferably at least three or more of the hydrotreatment reactor, the hydrotreatment catalyst, the separation stage, the hydrocracking reactor, and / or the hydrocracking catalyst are as originally configured to treat a petroleum feed.

[0075] There may be further steps included after recovery of the at least three different distillates, and the residual marine fuel component. These may include e.g. hydropolishing, dearomatizing, stabilisation, just to name a few. Typically, such additional process steps aim at better control of desired properties of the recovered fractions.

[0076] The present process provides high flexibility regarding recovery of different product slates, and high yield of distillates, especially middle distillates. The inventors found that by separating, at least periodically and preferably by splitting, a portion from the separation stage bottom reduces accumulation in the recycle loop of the heaviest components and / or components resistant to hydrocracking, thereby ensuring smooth operation of the hydrocracking unit and the separation stage, and contributing beneficially to the quality and distribution of all the fractions recovered from the separation stage. This may be attained particularly when the separation stage bottom has an initial boiling point of at least 300°C (EN ISO 3405-2019), preferably at least 320°C, more preferably at least 340°C. Typically the separation stage bottom has an initial boiling point within a range from 300°C to 420°C (EN ISO 3405-2019), preferably from 320°C to 410°C, more preferably from 340°C to 400°C.

[0077] Additionally it was noticed that the separated portion met several or essentially all specification requirements for at least one residual marine fuel category as laid down in ISO 8217-2017 Table 2, preferably at least category RMD, more preferably at least category RMB, or even category RMA. This may be achieved simply by splitting a portion from the separation stage bottom. The present process allows at least some of the renewable and / or circular content, desired also in the marine fuel sector, to end-up in the separation stage bottom. Hence, recovery of a residual marine fuel component from the separation stage bottom further improves the overall value of the product slate of the present process. In certain preferred embodiments, the residual marine fuel component is recovered from the separation stage bottom at a rate ranging from 3 wt.-% to 30 wt.-%, preferably from 3 wt.- % to 20 wt.-%, more preferably from 5 wt.-% to 15 wt.-%, based on the total weight of the separation stage bottom. When the recovery rate of the residual marine fuel component is fixed, i.e. maintained approximately constant, the hydrocracking conversion may vary and be increased e.g. by increasing the hydrocracking temperature and / or decreasing WHSV. Alternatively, the recovery rate of the residual marine fuel component may be varied preferably within the specified ranges, while targeting fixed hydrocracking conversion.

[0078] In certain preferred embodiments, the at least three different distillates include a naphtha fraction and at least:

[0079] - an aviation fuel range fraction and a heavy gas oil fraction, or

[0080] - a light gas oil fraction and a heavy gas oil fraction, or

[0081] - an aviation fuel range fraction and a middle gas oil fraction, preferably the at least three different distillates include a naphtha fraction, a heavy gas oil fraction, and an aviation fuel range fraction or a light gas oil fraction. Surprisingly it was found that the present process is able to distribute sustainable content to each of the recovered fractions / components, from the naphtha fraction to the residual marine fuel component.

[0082] In certain preferred embodiments, the at least three different distillates include at least three or more of:

[0083] - a naphtha fraction having a boiling point range within a range from IBP to 230°C (ASTM D7096-2019), preferably from 20°C to 220°C, and optionally a difference between T90 and T10 temperatures (ASTM D7096-2019) within a range from 30 °C to 150 °C, preferably from 50 °C to 120 °C;

[0084] - an aviation fuel range fraction having a boiling point range within a range from 120 °C to 310 °C (EN ISO 3405-2019), preferably from 130 °C to 300 °C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 40 °C to 200 °C, preferably from 60 °C to 180 °C; - a light gas oil fraction having a boiling point range within a range from 120°C to 330°C (EN ISO 3405-2019), preferably from 130°C to 320°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 190 °C;

[0085] - a middle gas oil fraction having a boiling point range within a range from 190°C to 390°C (EN ISO 3405-2019), preferably from 200°C to 380°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 200 °C; and / or

[0086] - a heavy gas oil fraction having a boiling point range within a range from 270°C to 430°C (EN ISO 3405-2019), preferably from 280°C to 410°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 5 °C to 140 °C, preferably from 10 °C to 100 °C.

[0087] These fractions are obtainable with good yields and cut widths and are usable in various applications and / or down-stream processings.

[0088] In certain preferred embodiments, at least a naphtha fraction is recovered from the separation stage, wherein the naphtha fraction preferably has a boiling point range within a range from 20°C to 200°C (ASTM D7096-2019), more preferably from 85°C to 190°C, and at least a portion thereof is fed to a catalytic naphtha reformer to obtain a reformate gasoline fraction. Surprisingly the present inventors found that a naphtha fraction is obtainable by the present process, that is especially useful as a (co-)feed to a catalytic naphtha reformer thanks to its high naphthenes content, allowing generation of a reformate gasoline fraction with good aromatics content, whereof a measurable portion may be biogenic. By selecting the initial boiling point of the naphtha fraction suitably, such as at least 85°C (ASTM D7096- 2019), the content of cyclohexane may be kept low, so that less or essentially no benzene is formed in the naphtha reformer from the naphtha fraction.

[0089] Hence, in certain embodiments at least a naphtha fraction is recovered from the separation stage, preferably as stabilised, wherein the naphtha fraction has at least one or more of the following properties: a density at 15°C within a range from 730 to 790 kg / m3 (EN ISO 12185-1996), preferably from 735 to 785 kg / m3, sulphur content at most 20 mg / kg (ASTM D5623-2019), preferably at most 15 mg / kg, - a weight ratio of naphthenes to aromatics at least 6.0 (GC-FID / GC-MS), preferably at least 8.0,

[0090] - aromatics content within a range from 0.5 to 15.0 wt.-% (GC-FID / GC-MS), preferably from 1.0 to 10.0 wt.-%,

[0091] - naphthenes content within a range from 40.0 to 90.0 wt.-% (GC-FID / GC-MS), preferably from 40.0 to 80.0 wt.-%,

[0092] - a content of cyclohexane less than 5.0 wt.-% (GC-FID / GC-MS), preferably less than 2.0 wt.-%, and / or

[0093] - a biogenic carbon content within a range from 1 to 50 wt.-%, preferably from 3 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

[0094] Typically, middle distillates represent the most valuable products in refinery’s product slate, especially when having renewable and / or circular content and sufficient quality for use in aviation or diesel fuels. An aviation fuel range fraction obtainable by the present process may, even as such, meet several or essentially all specification requirements as laid down in ASTM D1655-2023 Table 1 for an aviation fuel. A light gas oil fraction obtainable by the present process may, even as such, meet several or essentially all specification requirements as laid down in EN 590:2022 for a diesel fuel.

[0095] In certain preferred embodiments, at least an aviation fuel range fraction is recovered from the separation stage, wherein the aviation fuel range fraction has at least one or more of the following properties:

[0096] - a difference between T50 and T 10 temperatures (EN ISO 3405-2019) of at least 20°C, preferably at least 40°C,

[0097] - a T10 temperature at most 205°C (EN ISO 3405-2019), preferably at most 190°C,

[0098] - a kinematic viscosity at -20 °C at most 10.0 mm2 / s (EN ISO 3104-2020), preferably at most 8.0 mm2 / s,

[0099] - a density at 15°C within a range from 775 to 840 kg / m3 (EN ISO 12185-1996), preferably from 780 to 830 kg / m3,

[0100] - a flash point at least 38 °C (IP 170-2013, Abel closed-cup method), preferably at least 40 °C, sulphur content at most 20 mg / kg (EN ISO 20846-2019), preferably at most 10 mg / kg, - a content of naphthenes within a range from 40.0 to 80.0 wt.-% (GCxGC-FID / GCxGC- MS), preferably from 50.0 to 75.0 wt.-%,

[0101] - weight ratio of a sum amount of naphthenes and isoparaffins to the amount of n- paraffins (GCxGC-FID / GCxGC-MS) within a range from 4.0 to 25.0, preferably from 5.0 to 20.0,

[0102] - a freezing point at most -30°C (IP 529-2016), preferably at most -35°C, and / or

[0103] - a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

[0104] In certain preferred embodiments, at least a light gas oil fraction is recovered from the separation stage, wherein the light gas oil fraction has at least one or more of the following properties:

[0105] - a kinematic viscosity at 40°C within a range from 1.2 to 4.5 mm2 / s (EN ISO 3104-2020), preferably from 1 .5 to 4.0 mm2 / s,

[0106] - a density at 15°C within a range from 795 to 860 kg / m3 (EN ISO 12185-1996), preferably from 810 to 845 kg / m3,

[0107] - a flash point at least 50 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 55 °C,

[0108] - aromatics content at most 25.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 20.0 wt.-% ,

[0109] - a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.8 to 3.0, preferably from 1 .0 to 2.5,

[0110] - a cetane number at least 43.0 (EN 15195:2023), preferably at least 44.0,

[0111] - a cloud point at most +5°C (ASTM D7689-2021 ), preferably at most -5°C, and / or

[0112] - a biogenic carbon content within a range from 5 to 60 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

[0113] Shipping is the backbone of international trade, accounting for approximately 80% of global transportation measured by volume. Shipping is also responsible for 2-3% of global GHG emissions. Bringing it to zero is a huge challenge. The marine fuel range components obtainable by the present process having renewable and / or circular content will help to reduce GHG emissions and meet the target of 50% GHG emission reduction by 2050. A residual marine fuel component obtainable by the present process may, even as such, meet several or essentially all specification requirements for at least one residual marine fuel category as laid down in ISO 8217-2017 Table 2, preferably at least category RMD, more preferably at least category RMB, or even category RMA. Also, a heavy gas oil fraction and a middle gas oil fraction obtainable by the present process may find use in marine fuels. The recovered middle and / or heavy gas oil fraction may, even as such, meet several or essentially all specification requirements for at least one distillate marine fuel category as laid down in ISO 8217-2017 Table 1 , preferably at least category DMB, more preferably at least category DMZ, or even category DMA or DMX. Additionally, the recovered middle gas oil fraction may, even as such, meet several or essentially all specification requirements as laid down in EN 590:2022 for a diesel fuel.

[0114] Hence, in certain preferred embodiments, at least a middle gas oil fraction is recovered from the separation stage, wherein the middle gas oil fraction has at least one or more of the following properties:

[0115] - a kinematic viscosity at 40°C within a range from 2.0 to 11.0 mm2 / s (EN ISO 3104- 2020), preferably from 3.0 to 6.0 mm2 / s,

[0116] - a density at 15°C within a range from 815 to 900 kg / m3 (EN ISO 12185-1996), preferably from 820 to 860 kg / m3,

[0117] - a flash point at least 60 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 80 °C,

[0118] - sulphur content at most 50 mg / kg (EN ISO 20846-2019), preferably at most 5 mg / kg,

[0119] - aromatics content at most 30.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 25.0 wt.-%,

[0120] - a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.8 to 2.5, preferably from 1 .0 to 2.0,

[0121] - a cetane number at least 51 .0 (EN 15195:2023), preferably at least 55.0,

[0122] - a cloud point at most +10°C (ASTM D7689-2021 ), preferably at most +5°C, and / or

[0123] - a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TO) in the fraction (EN 16640:2017).

[0124] These embodiments may provide improved yield and / or quality of middle gas oil fractions usable in diesel fuel(s) and / or distillate marine fuel(s). In certain preferred embodiments, at least a heavy gas oil fraction is recovered from the separation stage, wherein the heavy gas oil fraction has at least one or more of the following properties:

[0125] - a kinematic viscosity at 40°C within a range from 4.0 to 12.0 mm2 / s (EN ISO 3104- 2020), preferably from 5.0 to 11 .0 mm2 / s,

[0126] - a density at 15°C within a range from 820 to 900 kg / m3 (EN ISO 12185-1996), preferably from 840 to 890 kg / m3,

[0127] - a flash point at least 80 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 100 °C,

[0128] - sulphur content at most 100 mg / kg (EN ISO 20846-2019), preferably at most 10 mg / kg,

[0129] - aromatics content at most 35.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 25.0 wt.-%,

[0130] - a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.5 to 1.5, preferably from 0.8 to 1.5,

[0131] - a cetane number at least 51 .0 (EN 15195:2023), preferably at least 55.0,

[0132] - a cloud point at most +25°C (ASTM D7689-2021 ), preferably at most +20°C, and / or

[0133] - a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

[0134] In certain preferred embodiments, the residual marine fuel component recovered from the separation stage bottom, preferably by splitting a portion from the separation stage bottom, has at least one or more of the following properties:

[0135] - a kinematic viscosity at 40°C within a range from 15 to 80 mm2 / s (EN ISO 3104-2020), preferably from 20 to 50 mm2 / s,

[0136] - a density at 15°C within a range from 850 to 975 kg / m3 (EN ISO 12185-1996), preferably from 860 to 920 kg / m3,

[0137] - a flash point at least 100 °C, preferably at least 120 °C (EN ISO 2719-2016 Pensky- Martens closed cup procedure),

[0138] - sulphur content at most 150 mg / kg (EN ISO 20846-2019), preferably at most 15 mg / kg,

[0139] - nitrogen content at most 10 000 mg / kg (ASTM D5762-2018a), preferably at most 8 000 mg / kg, aromatics content at most 50.0 wt.-% (ASTMD2549-02(2017)), preferably at most 30.0 wt.-%,

[0140] - lubricity, expressed as high-frequency reciprocating rig (HFRR) value, of at most 520 pm / 60°C (EN ISO 12156-1-2023), preferably at most 300 pm / 60°C, and / or

[0141] - a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 8 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

[0142] According to a second example aspect, there is provided a naphtha fraction having a boiling point range within a range from IBP to 230°C (ASTM D7096-2019), preferably from 20°C to 220°C, and a difference between T90 and T10 temperatures (ASTM D7096-2019) within a range from 30 °C to 150 °C, preferably from 50 °C to 120 °C, and optionally a biogenic carbon content within a range from 1 to 50 wt.-%, preferably from 3 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the naphtha fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0143] According to a third example aspect, there is provided an aviation fuel range fraction having a boiling point range within a range from 120 °C to 310 °C (EN ISO 3405-2019), preferably from 130 °C to 300 °C, a difference between T90 and T10 temperatures (EN ISO 3405- 2019) within a range from 40 °C to 200 °C, preferably from 60 °C to 180 °C, and optionally a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 10 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the aviation fuel range fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0144] According to a fourth example aspect, there is provided a light gas oil fraction having a boiling point range within a range from 120°C to 330°C (EN ISO 3405-2019), preferably from 130°C to 320°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 190 °C, and optionally a biogenic carbon content within a range from 5 to 60 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the light gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect. According to a fifth example aspect, there is provided a middle gas oil fraction having a boiling point range within a range from 190°C to 390°C (EN ISO 3405-2019), preferably from 200°C to 380°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 200 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the middle gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0145] According to a sixth example aspect, there is provided a heavy gas oil fraction having a boiling point range within a range from 270°C to 430°C (EN ISO 3405-2019), preferably from 280°C to 410°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 5 °C to 140 °C, preferably from 10 °C to 100 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the heavy gas oil fraction has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0146] According to a seventh example aspect, there is provided a residual marine fuel component having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, and optionally a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 8 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the residual marine fuel component has at least one or more further properties as defined in embodiments of the first example aspect, and is preferably obtainable by the process according to the first example aspect.

[0147] At least one or more of the recovered at least three different distillates, preferably selected from a naphtha fraction and at least: an aviation fuel range fraction and a heavy gas oil fraction, or a light gas oil fraction and a heavy gas oil fraction, or an aviation fuel range fraction and a middle gas oil fraction, may find use in a wide range of various applications, such as in transportation fuels, in feedstocks for industrial conversion processes, preferably in thermal cracking feedstocks, such as in steam cracking feedstocks, and / or in catalytic cracking feedstocks, in transformer oils, in heat-transfer media, in switchgear oils, in shock absorber oils, in insulating oils, in hydraulic fluids, in gear oils, in transmission fluids, in degreasing compositions, in penetrating oils, in anticorrosion compositions, in multipurpose oils, in metal working fluids, in rolling oils especially for aluminium, in cutting oils, in drilling fluids, in solvents, in lubricants, in extender oils, in carriers, in dispersant compositions, in demulsifiers, in extractants, in paint compositions, in coating fluids or pastes, in adhesives, in resins, in varnishes, in printing pastes or inks, in detergents, in cleaners, in plasticizing oils, in turbine oils, in hydrophobization compositions, in agriculture, in crop protection fluids, in construction, in concrete demoulding formulations, in electronics, in medical appliances, in compositions for car, electrical, textile, packaging, paper, cosmetic and / or pharmaceutical industry, and / or in manufacture of intermediates therefor. The elevated renewable and / or circular content, especially biogenic carbon content, that may be abundant particularly in the recovered middle distillate range fractions, add value in all these applications.

[0148] Schematic presentation of the process

[0149] Fig. 1 schematically shows a process according to an example embodiment. Fig. 1 also shows alternative ways of providing a hydrotreatment feed HTF having petroleum content as well as renewable and / or circular content. A sustainable (renewable and / or circular) feed S including at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and / or liquefied organic waste is introduced into a prehydroconversion reactor 100, optionally together with a petroleum feed P1. Additionally or alternatively, a petroleum feed P2 may be combined with the pre-hydroconversion effluent, and / or a petroleum feed P3 may be combined with a fraction of the pre-hydroconversion effluent, preferably with a pre-hydroconversion bottom fraction, obtained by subjecting the pre-hydroconversion effluent to a pre-hydroconversion fractionation 110. In the hydrotreatment reactor 200 the hydrotreatment feed HTF is subjected to hydrotreatment in the presence of a hydrotreatment catalyst, and optionally a dewaxing catalyst, to obtain a hydrotreatment effluent whereof at least a portion is introduced into a separation stage 300. From the separation stage 300 at least three different distillates 410, 420, 430, and a separation stage bottom 440 are recovered. A residual marine fuel component 440a is recovered from the separation stage bottom 440, preferably by splitting a portion therefrom. A hydrocracking feed comprising a portion of the separation stage bottom 440b is subjected to hydrocracking in a hydrocracking reactor 500 in the presence of a hydrocracking catalyst, and optionally a hydroisomerisation catalyst, to obtain a hydrocracking effluent 510, and at least a portion thereof is co-fed with the hydrotreatment effluent to the separation stage 300. EXAMPLES

[0150] EXAMPLE 1. Pre-hydroconversion of three different renewable feeds and cohydrotreatment with a petroleum feed

[0151] Feeds containing a conventionally purified crude tall oil (CTO), or its mixtures with conventionally purified animal fat (AF) were prepared. The CTO contained about 48 wt.-% fatty acids (e.g. oleic acid), about 29 wt.-% resin acids (e.g. abietic acid) and about 23 wt.- % neutrals (e.g. sterols). The feeds were subjected to a pre-hydrotreatment using a conventional NiMo hydrotreatment catalyst. The conditions of the pre-hydrotreatment step were as follows: a temperature from about 310 to about 340 °C, a pressure from about 50 to about 60 bar (abs) and WHSV from about 0.8 to about 1 .2 1 / h. The pre-hydrotreatment effluent was subjected to a gas-liquid separation, portion of the liquid stream was mixed with the pre-hydrotreatment feed as diluent (product recycle) and the thus-obtained saturated and deoxygenated renewable hydrocarbon stream was subjected to a distillation, from which a pre-hydrotreatment distillate and a pre-hydrotreatment fractionation bottom having an IBP of about 320 °C (about 340 °C for 100% CTO) were recovered. The prehydrotreatment fractionation bottom was utilised as a renewable component in a hydrotreatment feed, i.e. co-fed with a petroleum feed to the subsequent hydrotreatment. The tested hydrotreatment feeds having only petroleum content (petroleum reference PR) or petroleum and sustainable (here: renewable) contents (P + S), and components thereof, are summarised in Tables 1 A and 1 B.

[0152] Table 1 A. Brief description of the hydrotreatment feeds.

[0153] * distillate of hydrocracked mixture of crude oil vacuum distillate and vacuum distillation bottom as deasphalted

[0154] Table 1 B. Brief description of certain hydrotreatment feed components.

[0155] Hydrotreatment feeds were 100 wt.-% petroleum reference feed (PR), or 75 wt.-% of petroleum feed (P) co-fed with 25 wt.-% of sustainable component S1 , S2 or S3. The hydrotreatment feeds were hydrotreated in a hydrotreatment reactor using a conventional NiMo on alumina hydrotreatment catalyst and the following conditions: pressure about 16 MPa, temperature about 340-390 °C and LHSV about 0.8-1 .0 h“1.

[0156] From the hydrotreatment effluent a gaseous stream containing gases and low-boiling hydrocarbons was removed to obtain a liquid hydrocarbon stream that was distilled to obtain gasoline boiling range fraction, middle distillate fractions, and a separation stage bottom. A portion of the separation stage bottom was separated as a bleed. This helps to maintain the quality of the recycle stream i.e. the remaining portion of the separation stage bottom to be fed to hydrocracking. The amount of the bleed is influenced by the content of heavies, and by the severity of the hydrocracking conditions. For example, at relatively low hydrocracking temperature, some of the heavies may survive hydrocracking conditions, and consequently increase the bleed amount.

[0157] The remaining portion of the separation stage bottom was then fed to hydrocracking in a hydrocracking reactor, using conventional hydrocracking catalyst (incl. noble metals on an acidic porous material), and the following conditions: pressure about 16 MPa, temperature about 340-390 °C and LHSV about 0.8-1 .0 h“1. From the hydrocracking effluent a gaseous stream containing gases and low-boiling hydrocarbons was removed to obtain a liquid hydrocarbon stream that was co-fed with the degassed hydrotreatment effluent to the distillation. This recycling was continued throughout the test runs. Product fractions were recovered after reaching a steady state. Yields of the recovered fractions and change (%) compared to test run using petroleum feed reference P alone as the hydrotreatment feed are reported in Table 2.

[0158] Table 2. Yields of the recovered fractions, and change (%) compared to using petroleum reference feed PR alone as the hydrotreatment feed.

[0159] From Table 2 it can be seen, that by co-processing 25 wt.-% of the sustainable component S1 , S2 or S3, 5-6 wt.-% higher middle distillates yield could be obtained compared to processing petroleum reference feed, corresponding to about 9% increase. At the same time the yield of gasoline range hydrocarbons was 4-7 wt.-% lower (i.e. decreased by about 40%), and the yield of separation stage bottom was same or at most 1-2 wt.-% higher (i.e. increased at most by about 10%). The combination of increased yield of middle distillates and reduced yield of gasoline range hydrocarbons is desired, as generally middle distillates have higher value compared to lighter hydrocarbons. Additionally, as shown in Examples 5 to 8, the middle distillate range products were found to have highly desired properties, making their increased yield even more valuable. Also the separation stage bottom was found to have improved value, as not only having sustainable content, but also being suitable for use as a residual marine fuel or as a component for distillate marine fuels, as shown in Example 9. Surprisingly co-processing a sustainable component also influenced the gas formation, which was reduced by about 50%, when the renewable feed contained animal fat. This may be seen as beneficial as light gases have lower value compared to liquid range products.

[0160] Based on the results shown in Table 2, it seems that the product distribution may be easily fine-tuned by selecting how the sustainable content is introduced. By subjecting a renewable and / or circular feed to a pre-hydrotreatment and fractionation, and co-feeding only the bottom fraction to the hydrotreatment, the yield of gasoline range hydrocarbons may be controlled, while by co-feeding a pre-hydrotreatment effluent just as degassed and optionally stabilised (without further fractionation), or by co-feeding e.g. non-pre- hydrotreated fatty feed, the yield of gasoline range hydrocarbons could be reduced less, or maintained, or even increased. At a typical petroleum refinery, adjusting the properties of the petroleum component of the hydrotreatment feed may be more difficult, as such adjustment would influence all other associated refinery units upstream and downstream, requiring multiple additional adjustments at the refinery and also involving a risk of negative impacts. The approach of the present process may provide an interesting possibility to balance the contribution of the sustainable content on the product slate, while allowing even very high incorporation rates of the sustainable content essentially without compromising the efficiency of the hydrotreatment step. This is important for ensuring sufficient saturation level and heteroatom removal, to obtain products meeting requirements for various uses or down-stream processing, such as very low sulphur and nitrogen contents. Hence incorporation of sustainable content provides not only higher value products due to the sustainable content, but also provides an easy and effective way to optimise the product slate e.g. based on market demand, availability of sustainable co-feeds and / or their quality.

[0161] EXAMPLE 2. Alternative renewable and / or circular feeds

[0162] Additionally, for illustration purposes, two sustainable feeds, namely a renewable feed R1 and a circular feed C1 , were provided. R1 was conventionally purified glyceridic feed of animal fat / vegetable oil, and C1 was conventionally purified liquefied waste plastic (obtained by thermal degradation / pyrolysis of polyolefinic waste plastics). R1 was subjected to a catalytic pre-hydrotreatment mixed with the pre-hydrotreated liquid stream (product recycle) as diluent, followed by gas-liquid separation. C1 was subjected to catalytic prehydrotreatment followed by gas-liquid separation and further fractionation. Certain characteristics of the thus obtained pre-hydrotreated renewable feed R1 and prehydrotreated circular feed C1 were then analysed and are reported in Table 3. Table 3. Certain characteristics of a pre-hydrotreated renewable feed R1 and a prehydrotreated circular feed C1. Contents of n-paraffins, isoparaffins, naphthenes and aromatics, as well as of certain carbon number ranges, were determined by GCxGC- FID / GCxGC-MS.

[0163] Additionally, for illustration purposes, two sustainable feeds, namely a renewable feed R1 and a circular feed C1 , were provided. R1 was conventionally purified glyceridic feed of animal fat / vegetable oil, and C1 was conventionally purified liquefied waste plastic (obtained by thermal degradation / pyrolysis of polyolefinic waste plastics). R1 was subjected to a catalytic pre-hydrotreatment mixed with the pre-hydrotreated liquid stream (product recycle) as diluent, followed by gas-liquid separation. C1 was subjected to catalytic prehydrotreatment followed by gas-liquid separation and further fractionation. Certain characteristics of the thus obtained pre-hydrotreated renewable feed R1 and prehydrotreated circular feed C1 were then analysed and are reported in Table 3.

[0164] Table 3. Certain characteristics of a pre-hydrotreated renewable feed R1 and a prehydrotreated circular feed C1. Contents of n-paraffins, isoparaffins, naphthenes and aromatics, as well as of certain carbon number ranges, were determined by GCxGC- FID / GCxGC-MS.

[0165] EXAMPLE 3. Yields of recoverable fractions I products

[0166] In the following is presented yields of exemplary fractions I products that may be recovered from the present process (using the feeds and process as disclosed in Example 1 ). Properties of the recovered fractions and their suitability for certain uses were also studied, and are reported in Examples 4 to 9.

[0167] Table 4. Estimated yields (wt.-%) and approximate boiling ranges (IBP-FBP, °C) of fractions recoverable from the present process, with hydrotreatment feeds containing 75 wt.-% petroleum feed and 25 wt.-% sustainable feed S2 or S3.

[0168] Example 4. Naphtha fractions - Heavy naphtha

[0169] Table 5. Certain characteristics of heavy naphtha fractions obtained by the present process using three different renewable pre-hydrotreatment feeds, and of a heavy naphtha fraction obtained by otherwise similar process using petroleum reference feed PR. Contents of paraffins, naphthenes, olefins, heteroatomic compounds and aromatics were determined by GC-FID / GC-MS.

[0170] The research octane number, RON, may be measured for the neat naphtha fraction or for the naphtha fraction blended with another gasoline component having a known octane number, then given as blending RON (bRON). As used throughout this text, bRON refers to measured bRON after correction, i.e. corrected value obtained after subtracting 0.2 from the measured value (in accordance with section 5.6 of EN 228:2012 amended 2017). Throughout this text clean research octane numbers are meant, i.e. as achieved without using octane boosting additives. A standard method for RON measurement is given e.g. in ASTM D2699-2022 or EN ISO 5164-2014. Measuring and calculating bRON is known in the field and has been published for example in US4244704A. Due to low volumes of the samples, here the octanes were determined from blends with a commercial gasoline component having high i-paraffin content (alkylate), referred to as “2nd component”. The blending octane numbers for bRON samples were calculated using the following equation:

[0171] Surprisingly incorporation of the renewable content led to increase in the bRON values, compared to the 100% petroleum reference, as reported in the above Table, thereby enhancing the value of the naphtha fraction obtainable by the present process as a blend component in gasoline fuels. The results show that the higher the CTO content in the prehydrotreatment feed, the higher the bRON of the naphtha fraction.

[0172] From the Table above it can also be seen that the present process is able to produce a naphtha fraction having renewable content without essentially changing other properties thereof, compared to the 100% petroleum reference. From a process point of view, it is highly beneficial that incorporation of renewable content e.g. in an intermediate stream used as (co)feed in another process unit does not essentially change it otherwise, thereby reducing or avoiding need for adaptation of said down-stream process. Enhanced flexibility is achieved, so that a predominantly petroleum-fed refinery may from time to time be co-fed also with renewable and / or circular feeds, or an at least partly sustainable refinery may from time to time return to feeding petroleum feed only, e.g. depending on the availability of suitable renewable and / or circular feeds, without a need to adapt the down-stream process back and forth. With suitable selection of the IBP, e.g. content of cyclohexane (boiling at about 81 °C) may be minimised e.g. to «1 wt.-%, making the naphtha fraction obtainable by the present process an excellent (co)feed to a reformer unit, where the high naphthenes content may be converted to high aromatics content, yet without essential increase in benzene content. This is beneficial for the use of the thus-obtained reformate as a gasoline fuel component.

[0173] The naphtha fraction obtainable by the present process also provides advantages over 100% renewable gasoline fuel range components produced by HDO and isomerisation of fatty feedstocks (HVO gasoline). Typical HVO gasolines have very high paraffin content (>90wt.-%), high n-paraffin content (>40 wt.-%), very low naphthenes content (<10 wt.-%) and essentially no aromatics, limiting their octane rating and hence blending ratio. The naphtha fractions obtainable by the present process have at least as high naphthenes content as the 100% petroleum reference, despite having biogenic carbon content of 8 to 20 wt.-%, based on the total weight of carbon (TC) in the fraction, and also the aromatics content is comparable.

[0174] Example 5. Aviation fuel range fractions

[0175] Table 6. Certain characteristics of an aviation fuel range fraction (Bio-AFC) obtained by the present process using CTO as pre-hydrotreatment feed, of 100% fossil JETA1 aviation fuel and of their two blends, as well as certain aviation fuel specification properties laid down in ASTM D1655-23, Table 1 and Table A1.1. Contents of paraffins, naphthenes, and aromatics were determined by GCxGC-FID / GCxGC-MS (except when otherwise stated).

[0176] * EN ISO 3405 as calculated based on values measured by ASTM D2887-2022e1

[0177] ** ASTM D7236-16a(2021 ) (Small Scale Closed Cup)

[0178] # ASTM D1655-23 Table A1.1 Extended requirements

[0179] From the Table above it can be seen that the present process is able to produce an aviation fuel range fraction having not only renewable content but also otherwise desired properties for a blending component for aviation fuels. For example 100% renewable aviation fuel components produced by HDO and isomerisation of fatty feedstock (HVO SAF) often have density that is at the lower end of the ASTM D7566-2021 Table 1 requirements, or even below, limiting its blending ratio. Typical HVO SAF also has a lower net heat of combustion on volume basis compared to fossil aviation fuel components. The aviation fuel range fraction obtainable by the present process has a significantly higher density, and also higher net heat of combustion on volume basis, which is comparable to that of fossil aviation fuel components. For high performance, volume-limited aircraft, the net heat of combustion per unit mass and the volume of fuel loaded determine the total safe range. Also the proper operation of an aircraft engine requires a maximum net energy of combustion per unit volume of the aviation fuel. Hence it would be highly beneficial that incorporation of a blend component having renewable content does not reduce the net heat of combustion of the fuel on volume basis. Incorporation of the aviation fuel range fraction obtainable by the present process actually increases the net heat of combustion of the aviation fuel. Furthermore, the presently provided aviation fuel range fraction has a very low naphthalenes content, but contrary to e.g. HVO SAF, a much higher aromatics content, about 9 wt.-%, which by no means limits its incorporation ratio as a blending component, but helps to meet the extended specification of min. 8.4 wt.-% aromatics, laid down in ASTM D1655-23 Table A1.1 extended requirements.

[0180] WO2021105557 discloses an aviation fuel range fraction obtainable by a somewhat similar process as disclosed here, however using a hydrotreatment feed containing nonhydrotreated tall oil pitch (TOP) and a petroleum feed. The aviation fuel range fraction obtained in WO2021105557 was found to be suitable as a blend component in aviation fuels, but it had to be recovered as relatively narrow cut (T50-T 10 14°C; T90-T 10 30°C) and also its final boiling point had to be limited (FBP 250°C), so as to control its properties, such as fluidity, to allow its incorporation in aviation fuels still meeting e.g. kinematic viscosity at -20°C specification requirement, as laid down in ASTM D1655-2023, Table 1. From the Table above it can be seen that the present process enables recovery of an aviation fuel range fraction as a much wider boiling cut and with a higher FBP, and still with sufficient fluidity in terms of kinematic viscosity at -20°C to allow its incorporation in aviation fuels in elevated blending ratios.

[0181] Example 6. Light gas oil (LGO) fractions

[0182] Table 7. Certain characteristics of light gas oil fractions obtained by the present process using three different renewable pre-hydrotreatment feeds, and of a light gas oil fraction obtained by otherwise similar process using petroleum reference feed PR, as well as certain diesel fuel specification properties laid down in EN 590:2022. Chemical compositions i.e. contents of paraffins, naphthenes, and aromatics were determined by GCxGC-FID / GCxGC- MS. EN590:2022 Table 2 refers to climate related requirements for temperate climate diesels, and EN 590:2022 Table 3 to climate related requirements for arctic and severe winter climate diesels.

[0183] From the Table above it can be seen that incorporation of the renewable content led to improvement of cetane number. Hence, less or no cetane improver may be required to meet e.g. the cetane specification requirement as laid down in EN 590:2022. A decline in cloud point and CFPP was observed, but only when using renewable pre-hydrotreatment feed containing 70 wt.-% of animal fat. When using 100 wt.-% CTO, the cloud point and CFPP remained essentially the same as for the 100% petroleum reference. The fractions could be recovered with broad boiling ranges, and with significant biogenic carbon contents (17-23 wt.-%, based on the total weight of carbon (TC) in the fraction).

[0184] The above Table shows that the light gas oil fractions obtained by the present process meet the diesel fuel specification requirements of EN 590:2022 for all properties as neat, except for flash point, this however being easily solved by slight adjustment of the cut-point (IBP). The results hence show that the light gas oil fractions obtainable by the present process may be used as blend components or even as neat for diesel fuels: the fraction obtained using pre-hydrotreatment feed containing 30wt.-% of CTO is suitable as neat in temperate climate diesel fuels (EN 590:2022 Tables 1 & 2), and the fractions obtained using prehydrotreatment feeds having higher CTO content are suitable as neat in severe and arctic winter climate diesel fuels (EN 590:2022 Tables 1 & 3). In view of the significant biogenic carbon contents, it is surprising that such good cold properties are achievable without isomerisation.

[0185] Example 7. Middle gas oil (MGO) fractions

[0186] Table 8. Certain characteristics of middle gas oil fractions obtained by the present process using three different renewable pre-hydrotreatment feeds, and of a middle gas oil fraction obtained by otherwise similar process using petroleum reference feed PR, as well as certain diesel fuel specification properties laid down in EN 590:2022 and certain marine fuel specification properties laid down in ISO 8217-2017, Table 1 (distillate marine fuels), for example category DMA. Contents of paraffins, naphthenes, and aromatics were determined by GCxGC-FID / GCxGC-MS. EN590:2022 Table 2 refers to climate related requirements for temperate climate diesels, and EN 590:2022 Table 3 to climate related requirements for arctic and severe winter climate diesels.

[0187] From the Table above it can be seen that incorporation of the renewable content led to increased kinematic viscosity, improved cetane number, and reduced aromatics content. Also a decline in cold properties, including cloud point and CFPP, was observed.

[0188] The above Table also shows that the middle gas oil fractions obtained by the present process meet or exceed the distillate marine fuel specification requirements of ISO 8217- 2017, Table 1 categories DMA, DMZ and DMB, on all accounts. Surprisingly this is achieved with substantial biogenic carbon content in the middle gas oil fractions. Due to the high quality these fractions could therefore be used for improving distillate marine fuel properties and / or for optimising the economics of the blend, for example by blending with fractions that do not meet the ISO 8217-2017 Table 1 requirements for DMA, DMZ or DMB, or by blending these fractions with other components / fractions to produce fuels fulfilling DMX, DMA, DMZ, RMA, RMB, RMD, RME, RMG, or RMK requirements as laid down in ISO 8217-2017.

[0189] Additionally the above Table shows that the middle gas oil fractions obtained by the present process meet the diesel fuel specification requirements of EN 590:2022 for all properties, except for density when using pre-hydrotreatment feed containing 60 wt.-% or more of CTO. However, density could be easily adjusted for example by limiting the distillation end-point (FBP). The results hence show that the middle gas oil fractions obtained by the present process may be used as blend components, or even as neat in diesel fuels.

[0190] In the following, results of a blending test with 100% renewable winter grade HVO diesel (NRD) and 100% petroleum arctic grade diesel (DIR) are reported. Density, viscosity, biogenic carbon content and chemical compositions for the blends are presented in the Table below. Viscosities have been calculated based on values measured (EN ISO 3104- 2020) for the blend components as neat using Walther empirical correlation and mixing rule for viscosity. Other properties have been calculated with linear equations based on values measured for the blend components as neat (density at 15°C by EN ISO 12185-1996, biogenic carbon content by EN 16640:2017, and contents of n-paraffins (nP), isoparaffins (iP), naphthenes (N) and aromatics (A) by GCxGC-FID / GCxGC-MS).

[0191] Table 9. Density, viscosity, biogenic carbon content and chemical compositions of 100% renewable winter grade HVO diesel (NRD) and 100% petroleum arctic grade diesel (DIR), as well as their blends with middle gas oil fractions obtained by the present process using three different renewable feeds (MGOs obtained with P+S1 , P+S2, or P+S3), and with a middle gas oil fraction obtained by otherwise similar process using petroleum reference feed PR. Blending amounts are presented as vol-%. Density, kinematic viscosity, biogenic carbon content, and contents of n-paraffins (nP), isoparaffins (iP), naphthenes (N) and aromatics (A) were obtained as explained above.

[0192] From the above Table it can be seen that the middle gas oil fractions obtained by the present process can be used as blend components e.g. with 100% petroleum arctic diesel (DIR) and 100% renewable winter grade HVO diesel (NRD) within broad blending ratios. Based on the above data the middle gas oil fractions obtained by the present process may be blended e.g. with the 100% renewable winter grade HVO diesel to meet EN590 specification requirements for temperate climate diesel in volume ratios ranging from about 55:45 to about 95:5, and with 100% petroleum arctic grade diesel (DIR) in volume ratios ranging from about 20:80 to about 90:10. Additionally, all of the middle gas oil fractions obtained by the present process help to control the total aromatics content when blended with 100% petroleum arctic diesel, and to increase the density to the required level when blended with 100% renewable winter grade HVO diesel. By using the middle gas oil fractions obtained by the present process and 100% renewable winter grade HVO diesel as the blend components, very high biogenic carbon contents were achieved while still meeting the density requirement for diesel fuels of EN 590:2022 Table 1 .

[0193] Example 8. Heavy gas oil (HGO) fractions

[0194] Table 10. Certain characteristics of heavy gas oil fractions obtained by the present process using three different renewable pre-hydrotreatment feeds, and of a heavy gas oil fraction obtained by otherwise similar process using petroleum reference feed PR, as well as certain diesel fuel specification properties laid down in EN 590:2022 and certain marine fuel specification properties laid down in ISO 8217-2017, Table 1 , for distillate marine fuel, category DMB. Contents of paraffins, naphthenes and aromatics were determined by GCxGC-FID / GCxGC-MS. EN590:2022 Table 2 refers to climate related requirements for temperate climate diesels, and EN 590:2022 Table 3 to climate related requirements for arctic and severe winter climate diesels.

[0195] From the Table above it can be seen that the heavy gas oil fractions obtained by the present process meet or exceed the distillate marine fuel specification requirements of ISO 8217- 2017, Table 1 category DMB, on all accounts. Pour points of the samples were not measured. Based on the cloud point and CFPP results, pour point should however not be an issue for DMB (ISO 8217-2017 limit for summer grade being +6°C). Surprisingly this is achieved with substantial biogenic carbon content in the heavy gas oil fractions (42-49 wt.- %, based on the total weight of carbon (TO) in the fraction). Due to the high quality these fractions could therefore be used for improving distillate marine fuel properties and / or for optimising the economics of the blend, for example by blending with fractions that do not meet the ISO 8217-2017 requirements for DMB, or by blending these fractions with other components / fractions to produce fuels fulfilling DMX, DMA, DMZ, RMA, RMB, RMD, RME, RMG or RMK requirements as laid down in ISO 8217-2017. Additionally the above Table shows that the heavy gas oil fractions obtained by the present process meet the diesel fuel specifications of EN 590:2022 for all other properties, except for density and viscosity. The results hence show that the middle gas oil fractions obtained by the present process could be used as blend components in diesel fuels together with other blend components having lower density and viscosity, such as with arctic grade diesel.

[0196] In the following, results of a blending test with 100% petroleum arctic grade diesel (DIR) are reported. Density, viscosity, biogenic carbon content and chemical compositions for the blends are presented in the Table below. Viscosities have been calculated based on values measured (EN ISO 3104-2020) for the blend components as neat using Walther empirical correlation and mixing rule for viscosity. Other properties have been calculated with linear equations based on values measured for the blend components as neat (density at 15°C by EN ISO 12185-1996, biogenic carbon content by EN 16640:2017, and contents of n- paraffins (nP), isoparaffins (iP), naphthenes (N) and aromatics (A) were determined by GCxGC-FI D / GCxGC-MS).

[0197] Table 11. Density, viscosity, biogenic carbon content and chemical compositions of 100% petroleum arctic grade diesel (DIR), as well as its blends with heavy gas oil fractions obtained by the present process using three different renewable feeds (HGOs obtained by processing P+S1 , P+S2, or P+S3), and with a heavy gas oil fraction obtained by otherwise similar process using petroleum reference feed PR. Blending amounts are presented as vol- %. Density, kinematic viscosity, biogenic carbon content, and contents of n-paraffins (nP), isoparaffins (iP), naphthenes (N) and aromatics (A) were obtained as explained above.

[0198] From the above Table it can be seen that the heavy gas oil fractions obtained by the present process can be used as blend components e.g. with 100% petroleum arctic diesel (DIR) within broad blending ratios. Based on the above data the heavy gas oil fractions obtained by the present process may be blended e.g. with the 100% petroleum arctic grade diesel (DIR) in volume ratios ranging from about 20:80 to about 70:30. Additionally, the heavy gas oil fractions obtained by the present process may help to control the total aromatics content when blended with 100% petroleum arctic diesel. By using the heavy gas oil fractions obtained by the present process and 100% petroleum arctic diesel as the blend components, biogenic carbon contents of at least 30wt.-%, based on the total weight of carbon (TC) in the fraction, were achieved while still meeting the density and viscosity requirement for diesel fuels of EN 590:2022 Table 1 .

[0199] Example 9. Separation stage bottom - residual marine fuel component Table 12. Certain characteristics of residual marine fuel components obtained by the present process using three different renewable pre-hydrotreatment feeds, and of a residual marine fuel component obtained by otherwise similar process using petroleum reference feed PR, as well as certain marine fuel specification properties laid down in ISO8217-2017, Table 2 (residual marine fuel) category RMB. From Table 12 it can be seen that the present process is able to produce marine fuel range components having not only surprisingly high renewable content but also otherwise desired properties for a blending component for residual marine fuels (i.e. residual marine fuel components).

[0200] Most of the results reported in Table 12 are within the requirements for residual marine fuel grade RMB according to ISO 8217-2017, Table 2. Actually, the obtained residual marine fuel component could also be used as a blending component for distillate marine fuel according to ISO 8217-2017, Table 1 category DMB. When renewable content is incorporated in the hydrotreatment feed, the flash point increases, which is beneficial for marine fuels. The pour points are above specification limit, as well as kinematic viscosity at 50°C. This is however not of concern, as these properties may be adjusted into specification e.g. with other blending components. Additionally, pour point is often not an issue for ships using residual grade fuels as these employ heating of the fuel to treat the fuel onboard prior to use. The residual marine fuel components recovered from the present process have significantly reduced sulphur, nitrogen and oxygen contents. This is beneficial for use in fuels. One of the most significant findings is the surprisingly high biogenic carbon content in the recovered residual marine fuel components, even 33 wt.-%, based on the total weight of carbon (TC) in the component. The results show that the higher the CTO content in the pre-hydrotreatment feed, the higher the biogenic carbon content in the recovered residual marine fuel component. In addition to the high biogenic carbon content, another significant finding was the improved lubricity (HFRR). The higher the CTO content in the prehydrotreatment feed, the better the HFRR results. HFRR result for the fully petroleum based residual marine fuel component (reference) was 210 pm / 60°C. When 60 wt-% of the renewable feed used in the pre-hydrotreatment was CTO, the result was improved by 28 pm / 60°C to 182 pm / 60°C, and when the renewable feed in the pre-hydrotreatment was 100 wt.-% CTO, the result was improved by 73 pm / 60°C (compared to the reference) giving a result of 137 pm / 60°C.

[0201] WO2022129681 discloses a marine fuel range component obtainable by prehydrotreatment of tall oil pitch (TOP) and distillation to recover a pre-hydrotreatment distillation bottom. The pre-hydrotreatment distillation bottom obtained in WO2022129681 was found to be suitable as a blend component in residual marine fuels, but it had >16 times higher nitrogen content and 2.5-3.5 times higher aromatics content compared to the marine fuel range component obtainable by the present process. High aromatics content in fuels is generally associated with increased soot and smoke formation, and N content in NOx formation upon combustion. The present process enables provision of a residual marine fuel component with renewable content having improved properties for use in marine fuels, especially due to its very low S and N content, low aromatics content, high flash point, and good lubricity in terms of HFRR.

[0202] Various embodiments have been presented. It should be appreciated that in this document, words comprise, include and contain are each used as open-ended expressions with no intended exclusivity.

[0203] The foregoing description has provided by way of non-limiting examples of particular implementations and embodiments of the invention a full and informative description of the best mode presently contemplated by the inventors for carrying out the invention. It is however clear to a person skilled in the art that the invention is not restricted to details of the embodiments presented in the foregoing, but that it can be implemented in other embodiments using equivalent means or in different combinations of embodiments without deviating from the characteristics of the invention.

[0204] Furthermore, some of the features of the afore-disclosed embodiments of this invention may be used to advantage without the corresponding use of other features. As such, the foregoing description shall be considered as merely illustrative of the principles of the present invention, and not in limitation thereof. Hence, the scope of the invention is only restricted by the appended patent claims.

Claims

CLAIMS1 . A process for producing hydrocarbon fractions, the process comprising: a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste to a pre-hydroconversion in a pre-hydroconversion reactor in the presence of a pre-hydroconversion catalyst to obtain a pre-hydroconversion effluent, and co-feeding a petroleum feed to the pre-hydroconversion reactor and / or combining a petroleum feed with at least a fraction of the prehydroconversion effluent, to obtain a hydrotreatment feed having petroleum content as well as renewable and / or circular content, b) subjecting the hydrotreatment feed to hydrotreatment in a hydrotreatment reactor in the presence of a hydrotreatment catalyst to obtain a hydrotreatment effluent, c) introducing at least a portion of the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least three different distillates, and a separation stage bottom having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, d) recovering a residual marine fuel component from the separation stage bottom, preferably by splitting a portion from the separation stage bottom, e) subjecting a hydrocracking feed comprising a portion of the separation stage bottom to hydrocracking in a hydrocracking reactor in the presence of a hydrocracking catalyst to obtain a hydrocracking effluent, and co-feeding at least a portion of the hydrocracking effluent with the hydrotreatment effluent to the separation stage.

2. The process according to claim 1 , wherein the at least three different distillates include a naphtha fraction and at least:- an aviation fuel range fraction and a heavy gas oil fraction, or- a light gas oil fraction and a heavy gas oil fraction, or- an aviation fuel range fraction and a middle gas oil fraction,- preferably the at least three different distillates include a naphtha fraction, a heavy gas oil fraction, and an aviation fuel range fraction or a light gas oil fraction.

3. The process according to claim 1 or 2, wherein the at least three different distillates include at least three or more of:- a naphtha fraction having a boiling point range within a range from IBP to 230°C (ASTM D7096-2019), preferably from 20°C to 220°C, and optionally a difference between T90 and T10 temperatures (ASTM D7096-2019) within a range from 30 °C to 150 °C, preferably from 50 °C to 120 °C;- an aviation fuel range fraction having a boiling point range within a range from 120 °C to 310 °C (EN ISO 3405-2019), preferably from 130 °C to 300 °C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 40 °C to 200 °C, preferably from 60 °C to 180 °C;- a light gas oil fraction having a boiling point range within a range from 120°C to 330°C (EN ISO 3405-2019), preferably from 130°C to 320°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 190 °C;- a middle gas oil fraction having a boiling point range within a range from 190°C to 390°C (EN ISO 3405-2019), preferably from 200°C to 380°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 200 °C; and / or- a heavy gas oil fraction having a boiling point range within a range from 270°C to 430°C (EN ISO 3405-2019), preferably from 280°C to 410°C, and optionally a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 5 °C to 140 °C, preferably from 10 °C to 100 °C.

4. The process according to any one of the preceding claims, wherein the residual marine fuel component is recovered from the separation stage bottom at a rate ranging from 3 wt.-% to 30 wt.-%, preferably from 3 wt.-% to 20 wt.-%, more preferably from 5 wt.-% to 15 wt.-%, based on the total weight of the separation stage bottom.

5. The process according to any one of the preceding claims, wherein a recycle hydrogen stream, fuel gases and / or a light naphtha fraction is / are further recovered from the separation stage, and at least a portion of the fuel gases and / or a light naphtha fraction is fed to a hydrogen production unit, preferably to a steam reforming unit, to obtain a syngas, followed by recovering a make-up hydrogen stream from the syngas; and optionally at least a portion of the recycle hydrogen stream and / or the make-up hydrogen stream is recycledto the pre-hydroconversion in step a), to the hydrotreatment in step b), and / or to the hydrocracking in step e).

6. The process according to any one of the preceding claims, wherein at least a naphtha fraction is recovered from the separation stage, wherein the naphtha fraction preferably has a boiling point range within a range from 20°C to 200°C (ASTM D7096-2019), more preferably from 85°C to 190°C, and at least a portion thereof is fed to a catalytic naphtha reformer to obtain a reformate gasoline fraction.

7. The process according to any one of the preceding claims, wherein the hydrotreatment feed has a petroleum content within a range from 5 to 95 wt.-%, preferably from 10 to 95 wt.-%, more preferably from 15 to 90 wt.-%, even more preferably from 20 to 85 wt.-%.

8. The process according to any one of the preceding claims, wherein the petroleum feed comprises more than 30 wt.-%, preferably more than 40 wt.-%, more preferably more than 50 wt.-% of hydrocarbons boiling within a range from 100 °C to 400 °C (ASTM D2887- 2023), and more than 10 wt.-%, preferably at least 20 wt.-%, more preferably at least 30 wt.-%, of hydrocarbons boiling above 380°C (ASTM D2887-2023), based on the total petroleum feed weight; and / or at least one or more of atmospheric distillation bottom(s); vacuum distillate(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric distillation bottom(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked vacuum distillate(s); and / or atmospheric bottom(s) of (hydro)cracked vacuum distillate(s), of a petroleum crude oil.

9. The process according to any one of the preceding claims, wherein the process comprises a) subjecting at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), and / or liquefied organic waste, preferably at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s), to the pre-hydroconversion.

10. The process according to any one of the preceding claims, wherein at least a naphtha fraction is recovered from the separation stage, preferably as stabilised, wherein the naphtha fraction has at least one or more of the following properties:- a density at 15°C within a range from 730 to 790 kg / m3 (EN ISO 12185-1996), preferably from 735 to 785 kg / m3,- sulphur content at most 20 mg / kg (ASTM D5623-2019), preferably at most 15 mg / kg,- a weight ratio of naphthenes to aromatics at least 6.0 (GC-FID / GC-MS), preferably at least 8.0,- aromatics content within a range from 0.5 to 15.0 wt.-% (GC-FID / GC-MS), preferably from 1.0 to 10.0 wt.-%,- naphthenes content within a range from 40.0 to 90.0 wt.-% (GC-FID / GC-MS), preferably from 40.0 to 80.0 wt.-%,- a content of cyclohexane less than 5.0 wt.-% (GC-FID / GC-MS), preferably less than 2.0 wt.-%, and / or- a biogenic carbon content within a range from 1 to 50 wt.-%, preferably from 3 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).11 . The process according to any one of the preceding claims, wherein at least an aviation fuel range fraction is recovered from the separation stage, wherein the aviation fuel range fraction has at least one or more of the following properties:- a difference between T50 and T10 temperatures (EN ISO 3405-2019) of at least 20°C, preferably at least 40°C,- a T10 temperature at most 205°C (EN ISO 3405-2019), preferably at most 190°C,- a kinematic viscosity at -20 °C at most 10.0 mm2 / s (EN ISO 3104-2020), preferably at most 8.0 mm2 / s,- a density at 15°C within a range from 775 to 840 kg / m3 (EN ISO 12185-1996), preferably from 780 to 830 kg / m3,- a flash point at least 38 °C (IP 170-2013, Abel closed-cup method), preferably at least 40 °C,- sulphur content at most 20 mg / kg (EN ISO 20846-2019), preferably at most 10 mg / kg,- a content of naphthenes within a range from 40.0 to 80.0 wt.-% (GCxGC-FID / GCxGC- MS), preferably from 50.0 to 75.0 wt.-%,- weight ratio of a sum amount of naphthenes and isoparaffins to the amount of n-paraffins (GCxGC-FID / GCxGC-MS) within a range from 4.0 to 25.0, preferably from 5.0 to 20.0,- a freezing point at most -30°C (IP 529-2016), preferably at most -35°C, and / or- a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 10 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

12. The process according to any one of the preceding claims, wherein at least a light gas oil fraction is recovered from the separation stage, wherein the light gas oil fraction has at least one or more of the following properties:- a kinematic viscosity at 40°C within a range from 1.2 to 4.5 mm2 / s (EN ISO 3104-2020), preferably from 1 .5 to 4.0 mm2 / s,- a density at 15°C within a range from 795 to 860 kg / m3 (EN ISO 12185-1996), preferably from 810 to 845 kg / m3,- a flash point at least 50 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 55 °C,- aromatics content at most 25.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 20.0 wt.-% ,- a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.8 to 3.0, preferably from 1 .0 to 2.5,- a cetane number at least 43.0 (EN 15195:2023), preferably at least 44.0,- a cloud point at most +5°C (ASTM D7689-2021 ), preferably at most -5°C, and / or- a biogenic carbon content within a range from 5 to 60 wt.-%, preferably from 10 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

13. The process according to any one of the preceding claims, wherein at least a middle gas oil fraction is recovered from the separation stage, wherein the middle gas oil fraction has at least one or more of the following properties:- a kinematic viscosity at 40°C within a range from 2.0 to 11.0 mm2 / s (EN ISO 3104-2020), preferably from 3.0 to 6.0 mm2 / s,- a density at 15°C within a range from 815 to 900 kg / m3 (EN ISO 12185-1996), preferably from 820 to 860 kg / m3,- a flash point at least 60 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 80 °C,- sulphur content at most 50 mg / kg (EN ISO 20846-2019), preferably at most 5 mg / kg,- aromatics content at most 30.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 25.0 wt.-%,- a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.8 to 2.5, preferably from 1 .0 to 2.0,- a cetane number at least 51.0 (EN 15195:2023), preferably at least 55.0,- a cloud point at most +10°C (ASTM D7689-2021), preferably at most +5°C, and / or- a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

14. The process according to any one of the preceding claims, wherein at least a heavy gas oil fraction is recovered from the separation stage, wherein the heavy gas oil fraction has at least one or more of the following properties:- a kinematic viscosity at 40°C within a range from 4.0 to 12.0 mm2 / s (EN ISO 3104-2020), preferably from 5.0 to 11.0 mm2 / s,- a density at 15°C within a range from 820 to 900 kg / m3 (EN ISO 12185-1996), preferably from 840 to 890 kg / m3,- a flash point at least 80 °C (EN ISO 2719-2016 Pensky-Martens closed cup procedure), preferably at least 100 °C,- sulphur content at most 100 mg / kg (EN ISO 20846-2019), preferably at most 10 mg / kg,- aromatics content at most 35.0 wt.-% (GCxGC-FID / GCxGC-MS), preferably at most 25.0 wt.-%,- a weight ratio of naphthenes to paraffins (GCxGC-FID / GCxGC-MS) within a range from 0.5 to 1.5, preferably from 0.8 to 1.5,- a cetane number at least 51.0 (EN 15195:2023), preferably at least 55.0,- a cloud point at most +25°C (ASTM D7689-2021), preferably at most +20°C, and / or- a biogenic carbon content within a range from 5 to 80 wt.-%, preferably from 10 to 70 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

15. The process according to any one of the preceding claims, wherein the residual marine fuel component recovered from the separation stage bottom, preferably by splitting a portion from the separation stage bottom, has at least one or more of the following properties:- a kinematic viscosity at 40°C within a range from 15 to 80 mm2 / s (EN ISO 3104-2020), preferably from 20 to 50 mm2 / s,- a density at 15°C within a range from 850 to 975 kg / m3 (EN ISO 12185-1996), preferably from 860 to 920 kg / m3,- a flash point at least 100 °C, preferably at least 120 °C (EN ISO 2719-2016 Pensky- Martens closed cup procedure),- sulphur content at most 150 mg / kg (EN ISO 20846-2019), preferably at most 15 mg / kg,- nitrogen content at most 10 000 mg / kg (ASTM D5762-2018a), preferably at most 8 000 mg / kg,- aromatics content at most 50.0 wt.-% (ASTMD2549-02(2017)), preferably at most 30.0 wt.-%,- lubricity, expressed as high-frequency reciprocating rig (HFRR) value, of at most 520 pm / 60°C (EN ISO 12156-1-2023), preferably at most 300 pm / 60°C, and / or- a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 8 to 40 wt.- %, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

16. The process according to any one of the preceding claims, wherein step a) comprises feeding the pre-hydroconversion effluent to a pre-hydroconversion fractionation to recover one or more pre-hydroconversion distillate(s) and a pre-hydroconversion fractionation bottom, combining a petroleum feed with the pre-hydroconversion fractionation bottom to obtain the hydrotreatment feed; the process further comprising: f) feeding the one or more pre-hydroconversion distillate(s) to a catalytic conversion, preferably to a catalytic conversion comprising at least hydroisomerisation, more preferably to a catalytic conversion comprising at least hydroprocessing and hydroisomerisation, optionally with at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and / or liquefied organic waste, to obtain a catalytic conversion effluent; and g) optionally recovering from the catalytic conversion effluent at least an aviation fuel component and / or a diesel fuel component.

17. The process according to any one of the preceding claims, wherein in step a) the prehydroconversion comprises pre-hydrotreating and / or pre-hydrocracking, preferably at least pre-hydrotreating, in the pre-hydroconversion reactor in the presence of a prehydrotreatment and / or pre-hydrocracking catalyst(s), preferably at least pre-hydrotreatment catalyst, to obtain the pre-hydroconversion effluent.

18. The process according to any one of the preceding claims, wherein in step b) the hydrotreatment reactor further contains a dewaxing catalyst; and / or wherein in step e) the hydrocracking reactor further comprises a hydroisomerisation catalyst.

19. The process according to any one of the preceding claims, wherein the hydrotreatment in the hydrotreatment reactor is conducted at a temperature within a range from 300 °C to 450 °C, preferably from 350 °C to 420 °C, a pressure within a range from 6 MPa to 20 MPa, preferably from 10 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrotreatment reactor within a range from 6 MPa to 10 MPa, preferably from 10 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrotreatment feed per kg catalyst per hour, and a H2 to hydrotreatment feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter hydrotreatment feed; and / or wherein the hydrocracking in the hydrocracking reactor is conducted at a temperature within a range from 280 °C to 450 °C, preferably from 300 °C to 420 °C, a pressure within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrocracking reactor within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrocracking feed per kg catalyst per hour, and a H2 to hydrocracking feed ratio within a range from 50 to 2000, preferably from 500 to 1500 normal liters H2 per liter hydrocracking feed.

20. The process according to any one of the preceding claims, wherein the prehydroconversion comprises pre-hydrotreating, wherein the pre-hydrotreating is conducted at a temperature within a range from 300 °C to 420 °C, preferably from 320 °C to 380 °C, a pressure within a range from 3 MPa to 15 MPa, preferably from 4 MPa to 10 MPa, a H2 partial pressure at the inlet of a pre-hydroconversion reactor within a range from 3 MPa to 15 MPa, preferably from 4 MPa to 10 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg pre-hydroconversion feed per kg catalyst per hour, and a H2 to pre-hydroconversion feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter pre-hydroconversion feed, in the presence of a pre-hydrotreatment catalyst; and / or the pre-hydroconversion comprises pre-hydrocracking wherein the pre-hydrocracking is conducted at a temperature within a range from 280 °C to 450 °C, preferably from 300 °C to 420 °C, a pressure within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a H2 partial pressure at the inlet of a pre-hydroconversion reactor within a range from8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg pre-hydroconversion feed per kg catalyst per hour, and a H2 to pre-hydroconversion feed ratio within a range from 50 to 2000, preferably from 500 to 1500 normal liters H2 per liter pre-hydroconversion feed.

21. A naphtha fraction having a boiling point range within a range from IBP to 230°C (ASTM D7096-2019), preferably from 20°C to 220°C, and a difference between T90 and T10 temperatures (ASTM D7096-2019) within a range from 30 °C to 150 °C, preferably from 50 °C to 120 °C, and optionally a biogenic carbon content within a range from 1 to 50 wt.- %, preferably from 3 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the naphtha fraction has at least one or more further properties as defined in claim 10, and is preferably obtainable by the process according to any one of claims 1 to 20.

22. An aviation fuel range fraction having a boiling point range within a range from 120 °C to 310 °C (EN ISO 3405-2019), preferably from 130 °C to 300 °C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 40 °C to 200 °C, preferably from 60 °C to 180 °C, and optionally a biogenic carbon content within a range from 5 to 50 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the aviation fuel range fraction has at least one or more further properties as defined in claim 11 , and is preferably obtainable by the process according to any one of claims 1 to 20.

23. A light gas oil fraction having a boiling point range within a range from 120°C to 330°C (EN ISO 3405-2019), preferably from 130°C to 320°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 190 °C, and optionally a biogenic carbon content within a range from 5 to 60 wt.-%, preferably from 10 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the light gas oil fraction has at least one or more further properties as defined in claim 12, and is preferably obtainable by the process according to any one of claims 1 to 20.

24. A middle gas oil fraction having a boiling point range within a range from 190°C to 390°C (EN ISO 3405-2019), preferably from 200°C to 380°C, a difference between T90 and T10 temperatures (EN ISO 3405-2019) within a range from 50 °C to 200 °C, preferably from 80 °C to 200 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.- %, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction(EN 16640:2017), wherein the middle gas oil fraction has at least one or more further properties as defined in claim 13, and is preferably obtainable by the process according to any one of claims 1 to 20.

25. A heavy gas oil fraction having a boiling point range within a range from 270°C to 430°C (EN ISO 3405-2019), preferably from 280°C to 410°C, a difference between T90 andT10 temperatures (EN ISO 3405-2019) within a range from 5 °C to 140 °C, preferably from 10 °C to 100 °C, and optionally a biogenic carbon content within a range from 5 to 80 wt.- %, preferably from 10 to 70 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the heavy gas oil fraction has at least one or more further properties as defined in claim 14, and is preferably obtainable by the process according to any one of claims 1 to 20.

26. A residual marine fuel component having an initial boiling point of at least 300°C (EN ISO 3405-2019), such as within a range from 300°C to 420°C, preferably at least 320°C, such as within a range from 320°C to 410°C, more preferably at least 340°C, such as within a range from 340°C to 400°C, and optionally a biogenic carbon content within a range from5 to 50 wt.-%, preferably from 8 to 40 wt.-%, based on the total weight of carbon (TC) in the fraction (EN 16640:2017), wherein the residual marine fuel component has at least one or more further properties as defined in claim 15, and is preferably obtainable by the process according to any one of claims 1 to 20.

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