A process for producing hydrocarbon fractions having biogenic carbon content

Abstract

A process for producing hydrocarbon fractions having biogenic carbon content is provided In the process, a renewable feed comprising at least one or more of plant oil(s), animal fat(s), and / or microbial oil(s), and a heavy crude oil feed are provided. The heavy crude oil feed is subjected to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage. After an optional interstage separation flashing off a volatiles fraction, at least a non-volatiles fraction of the first hydroconversion stage effluent and the renewable feed are subjected to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage. The second hydroconversion stage effluent, and optionally the volatiles fraction from the interstage separation, is / are fed to a separation stage, and at least a heavy separation stage bottom usable in marine fuels and one or more distillate(s) are recovered.

Description

[0001] A PROCESS FOR PRODUCING HYDROCARBON FRACTIONS HAVING BIOGENIC CARBON CONTENT

[0002] TECHNICAL FIELD

[0003] The present disclosure generally relates to a process for producing hydrocarbon fractions having biogenic carbon content. The disclosure relates particularly, though not exclusively, to a process for producing at least a heavy separation stage bottom usable in marine fuels, especially in residual marine fuels according to ISO 8217-2017 Table 2, and one or more d isti llate(s) usable as feedstock(s) for downstream further conversion step(s).

[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] Fully biobased alternatives for drop-in replacements of fossil hydrocarbon products have been successfully created. For example Neste MY Renewable Diesel is a Hydrotreated Vegetable Oil (HVO) developed by Neste Corporation. It is made by NEXBTL™ process, which is a proprietary HVO process of Neste Corporation, from 100% renewable raw materials such as waste and residues, and results in as much as 75-95% less greenhouse gas (GHG) emissions over the fuel’s life cycle when compared with fossil diesel. Renewable Neste RE™, on the other hand, is a 100% renewable feedstock of Neste Corporation showing a GHG emission reduction of more than 85% over the life cycle when used to replace conventional fossil feedstock in the chemical and polymers industry.

[0008] In addition to the concepts dedicated for processing fully biogenic materials, for tackling global warming and vanishing crude oil reserves, as well as for meeting the above- mentioned needs, further solutions for industrial processes and products are urgently needed. In this regard, co-feeding of sustainable feed streams into existing petroleum refineries has a growing interest not least because of the existing infrastructure, allowing almost instant implementation. SUMMARY

[0009] 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 and / or producing a product slate having higher overall value. A further aim is to improve the yield of liquid hydrocarbons boiling within diesel range, or lighter, and having biogenic carbon content. Yet a further aim is to provide a heavy separation stage bottom that is usable in marine fuels and exhibits reduced sediment content and / or aged sediment content therein.

[0010] 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.

[0011] According to a first example aspect, there is provided a process for producing hydrocarbon fractions having biogenic carbon content, the process comprising: a) providing a renewable feed comprising at least one or more of plant oil(s), animal fat(s), and / or microbial oil(s); b) providing a heavy crude oil feed; c) subjecting the heavy crude oil feed to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a first hydroconversion stage effluent; d) subjecting at least a portion of the first hydroconversion stage effluent and the renewable feed to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a second hydroconversion stage effluent; and e) feeding the second hydroconversion stage effluent to a separation stage and recovering from the separation stage at least a heavy separation stage bottom, preferably a heavy vacuum tower bottom, and one or more distillate(s).

[0012] The inventors have found the present process and embodiments thereof to provide certain advantages compared to prior art processes. The advantages are related e.g to reducing GHG emissions and dependence from petroleum sources, improved overall economy and / or product slate having higher overall value. Further advantages were found in improved yields of biogenic carbon containing liquid hydrocarbons boiling within diesel range, or lighter, as well as in obtaining a heavy separation stage bottom usable in marine fuels. Surprisingly it was found that it is possible to reduce sediment content of a marine fuel blend and sediment formation in a marine fuel blend upon aging, when using a heavy separation stage bottom obtainable by the present process as the blend component. This was evidenced in the conducted experiments, where a heavy separation stage bottom obtained by the present process reduced blend sediment amount by at least 50%, and aged sediment amount by at least 35%, compared to a heavy separation stage bottom obtained by an otherwise similar process but without co-fed renewable feed. This was highly unexpected, as the amount of biogenic carbon content ending up in the heavy separation stage bottom was negligent. The reduction in sediment content, especially aged sediment content, is highly advantageous, because it allows the heavy separation stage bottom to be used in marine fuels in much wider blending ratios, and to reduce fouling of production equipment, as well as of fuel tanks and feeding systems of vessels. Additionally, in certain embodiments also a reduction in sulphur content of the recovered heavy separation stage bottom was observed. Any decrease in the heavy separation stage bottom’s sulphur level allows it to be used in marine fuels in higher blending ratios and / or blending with marine fuel components having higher sulphur content, thereby improving profits. The observed sulphur reduction was highly surprising in view of the very low, even negligible content of compounds originating from the renewable feed in the heavy separation stage bottom.

[0013] Hence, in certain preferred embodiments, the process further comprises incorporating at least a portion of the heavy separation stage bottom recovered in step e) into a marine fuel pool, preferably into a residual marine fuel pool.

[0014] An extensive processing e.g. at severe process conditions and / or in multiple steps is typically required for upgrading heavy crude oil feeds to liquid hydrocarbon range. Despite feeding the conventional fatty feed only to the second hydroconversion stage in the present process, it was expected that the renewable content would crack extensively and end up in the naphtha and gaseous fractions. However, the conducted experiments showed that the majority of the co-fed renewable content was allocated to the diesel boiling range. The diesel range fraction yield increased by over 40%, compared to an otherwise similar process but without co-fed renewable feed, and also the paraffins content thereof. Thanks to the higher paraffins content in the distillate(s), particularly in the middle distillate fraction(s) such as diesel range fraction, catalytic upgrading thereof is foreseen easier e.g. in terms of less severe process conditions, slower catalyst deactivation, reduced coking and plugging. Consequently fixed bed reactors may be utilised in the upgrading. Hence, in certain preferred embodiments, the process further comprises f) subjecting at least a portion of the distillate(s) recovered in step e) to one or more further conversion step(s), such as to one or more catalytic conversion step(s), preferably to one or more catalytic hydroprocessing step(s), more preferably to one or more catalytic hydroprocessing step(s) comprising at least one or more of a fixed bed catalytic hydrotreatment, a fixed bed catalytic hydrocracking, a fixed bed catalytic hydroisomerisation, and / or a fixed bed catalytic hydrodearomatisation. Hydroprocessing step(s), such as hydrotreatment, hydrocracking, hydroisomerisation, and / or hydrodearomatisation, are especially advantageous as high quality aviation fuel components, diesel components and / or solvents are attainable with good cold properties and / or reduced aromatics contents. As explained in the foregoing, the present process allows these to be conducted utilising fixed catalyst beds. In certain particularly preferred embodiments, the one or more catalytic hydroprocessing step(s) include an optional fixed bed catalytic hydrotreatment step arranged before one or more fixed bed catalytic hydrocracking step(s) and fixed bed catalytic hydroisomerisation step(s).

[0015] According to a second example aspect, there is provided use of a heavy separation stage bottom, such as a vacuum tower bottom, obtainable by the process according to the first example aspect, as a blend component in a marine fuel, especially in a residual marine fuel meeting one or more characteristics laid down in ISO 8217-2017 Table 2, preferably in an amount of 1 vol-% to 90 vol-% based on the marine fuel volume, wherein the heavy separation stage bottom preferably has T10 temperature (10 wt.-% recovered, EN15199- 2:2020) of at least 380°C, preferably at least 420°C, more preferably at least 450°C.

[0016] 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.

[0017] BRIEF DESCRIPTION OF THE FIGURES

[0018] Some example embodiments will be described with reference to the accompanying Figure 1 , which illustrates schematically an example embodiment of the present process.

[0019] DETAILED DESCRIPTION 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.

[0020] Unless otherwise stated, regarding distillation characteristics, such as T10 temperature (10 wt.-% recovered), T90 temperature (90 wt.-% recovered), and boiling point ranges (from IBP to FBP, unless otherwise specified), reference is made to GC-based methods (simulated distillation) ASTM D7096-2019 for naphtha or gasoline range fractions i.e. having final boiling point max. 280 °C, to ASTM D2887-2023 for middle distillates and vacuum gas oil distillates e.g. having final boiling point max 538 °C, and to EN15199-2:2020 for heavy feeds, fractions or residues having initial boiling points (IBP) above 100 °C and high final boiling points (FBP), even above 750 °C.

[0021] 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 EN15199-2:2020. 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.

[0022] 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. As used herein, hydrocarbons refer to compounds consisting of carbon and hydrogen, including paraffins, n-paraffins, i-paraffins, olefins, naphthenes, and aromatics. Heteroatomcontaining hydrocarbons, such as oxygenated hydrocarbons, refer herein to hydrocarbons comprising covalently bound heteroatom such as oxygen.

[0023] 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. 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. 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 of the number of branches. Correspondingly, “paraffins” refers to sum amount of any n-paraffins, and any i-paraffins, if present.

[0024] 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.

[0025] 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.

[0026] Chemically, the renewable (i.e. biological) or non-renewable (such as petroleum) origin of carbon-containing compounds, 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, co-feeds, 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).

[0027] In the context of this disclosure, CX or >CX hydrocarbons, fatty acids, or similar, refer to hydrocarbons, fatty acids, or similar, respectively, having a carbon number of X or at least X, where X is any feasible integer; CX-CY (or CX to CY) hydrocarbons, fatty acids, or similar, refer to at least hydrocarbons, fatty acids, 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 a specified range is not necessarily present, and that also compounds having a carbon number falling outside the specified range may be present.

[0028] By hydroconversion in the presence of a hydrotreatment catalyst is meant herein a process of treating organic material by means of molecular hydrogen at an elevated temperature. The hydrotreatment catalyst may be any conventionally used hydrotreatment catalyst or combination thereof, e.g. those well known in the fields of petroleum refining and / or renewable fuel production. The reactions occurring in the hydroconversion may include thermal and catalytic reactions, especially thermal cracking, but also catalytic cracking, ringopening, heteroatom cleavage, metal removal, etc, the catalytic reactions including particularly hydrotreatment reactions. 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 feed to the hydroconversion, particularly the composition of the feed fed to the hydroconversion stage or zone in question, different thermal and catalytic reactions may occur and / or prevail. Generally, the hydroconversion is capable of converting feeds of varying compositions to lower-boiling compounds e.g. by cracking, and to more pure materials, e.g. by reducing content of heteroatoms, metals, olefins, aromatics, or the like.

[0029] Hydroprocessing is used in the present disclosure as a general expression including various different catalytic processes conducted in the presence of added hydrogen, such as hydrotreatment, hydrocracking, hydroisomerisation and / or hydrodearomatisation, these processes, as well as reactors and catalysts usable therein being well known e.g. in the fields of petroleum refining and / or renewable fuel production.

[0030] In the present disclosure, the term “effluent" as in “hydroconversion stage effluent” refers to the effluent from a step of hydroconversion in the presence of a hydrotreatment catalyst, or to the effluent that may be obtained from any further conversion step(s), more specifically from further catalytic conversion step(s), excluding the catalyst and possibly formed coke. This applies to all process configurations, whether using fixed bed or moving catalyst bed configurations, such as ebullated beds.

[0031] In conventional petroleum refineries, crude oil distillation may yield atmospheric residue as much as about half of the crude oil feed. Also the yield of vacuum distillation residue is high, for example about 25% of the crude oil feed. The amount of these heavy fractions varies depending on the crude oil origin, heavier crude oil types yielding 2-3 times more vacuum residue compared to a medium or light crude oil type. Various technologies have been developed for converting such crude oil residues or heavy vacuum distillates - or in the context of the present process heavy crude oil feeds - to lighter fractions, in order to get value out of them. Such conversions may involve extensive processing, such as reducing the boiling point, increasing the hydrogen-to-carbon ratio, and removing impurities such as metals, sulfur, nitrogen and coke precursors. Exemplary conversions include hydrocracking processes using conventional heterogeneous catalysts to upgrade the heavy crude oil feeds for example by fixed-bed hydroprocessing, or by ebullated or other moving catalyst type hydroprocessings. Exemplary noncatalytic upgrading processes include thermal cracking, such as delayed coking, flexicoking, visbreaking, and solvent extraction. Despite an extensive processing of these heavy crude oil feeds, the bottom product remains as the lowest quality and highest impurities containing fraction among the recovered conversion products. Use thereof in marine fuels has been suggested, but quality improvements would help to relieve blending ratio limitations and / or fouling concerns. By hydroconverting a renewable feed, such as animal fat, in the present process also using a heavy crude oil feed, such as crude oil vacuum resid, it is possible to purify and convert both the renewable feed and the heavy crude oil feed predominantly to liquid hydrocarbons boiling below 400°C. Thanks to the renewable co-feed, hydrocarbon fraction(s) in this boiling range have biogenic carbon content, as well as elevated paraffin content, making such fraction(s) desired feedstocks for further conversion, particularly for hydroprocessing, such as hydrotreatment, hydrocracking, hydroisomerisation, and / or hydrodearomatisation, to obtain high quality aviation fuel components, diesel components and / or solvents with good cold properties and / or reduced aromatics contents. At the same time a heavy separation stage bottom is obtainable exhibiting reduced blend sediment content, especially aged blend sediment content, desired for use in marine fuels.

[0032] The present disclosure provides a process for producing hydrocarbon fractions having biogenic carbon content, the process comprising: a) providing a renewable feed comprising at least one or more of plant oil(s), animal fat(s), and / or microbial oil(s); b) providing a heavy crude oil feed; c) subjecting the heavy crude oil feed to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a first hydroconversion stage effluent; d) subjecting at least a portion of the first hydroconversion stage effluent and the renewable feed to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a second hydroconversion stage effluent; and e) feeding the second hydroconversion stage effluent to a separation stage, and recovering from the separation stage at least a heavy separation stage bottom, preferably a heavy vacuum tower bottom, and one or more distillate(s).

[0033] In the present process, in step c) the heavy crude oil feed is subjected to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a first hydroconversion stage effluent. In certain preferred embodiments, in step c) the first hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, wherein the moving catalyst bed is preferably an ebullated bed. In certain further preferred embodiments, in step c) the first hydroconversion stage comprises at least two hydroconversion zones in series each containing the hydrotreatment catalyst arranged in a moving catalyst bed, wherein the moving catalyst bed is preferably an ebullated bed. The heavy crude oil feed may be split between the hydroconversion zones of the first hydroconversion stage. For process simplicity it may be beneficial to utilise the same selection of hydrotreatment catalyst(s) in each hydroconversion zone of step c), while for flexibility e.g. regarding varying feed properties and / or optimisation of the yields and / or properties of the recovered fractions utilising a different selection of hydrotreatment catalyst(s) in each hydroconversion zone of step c) may be desired. Even though fixed bed systems have been developed and are being used for converting heavy crude oil feeds, for example as swing mode fixed bed systems, preferably the first hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, more preferably in an ebullated bed. Use of moving catalyst beds allows continuous catalyst renewing (addition and withdrawal) and / or regeneration during operation, allowing essentially constant catalyst activity, longer turnaround intervals and less down-time, and being especially beneficial when processing heavy crude oil feeds that typically also have elevated metal contents. Moving catalyst bed systems are devoid of issues common in fixed bed systems like catalyst bed plugging or channelling and allow maximal contact between the catalyst particles and the gaseous and liquid molecules of the feeds and formed intermediates. Additionally moving catalyst bed systems have essentially the same temperature throughout the reaction space (catalyst bed), so that formation of e.g. hot spots due to the exothermic reactions is not foreseen, and also the desired, high operating temperature can be ensured throughout the bed, which is important as significant part of the conversion to lower boiling components is advantageously due to thermal cracking. Consequently, use of moving catalyst beds ensures more constant conditions, reduced side reactions, and hence more constant product properties as well as constant, elevated yields of the distillate(s), especially of middle distillates boiling range. Ebullated beds are particularly preferred as in these reactors the catalyst is typically continuously or intermittently renewed i.e. withdrawn and replaced with fresh catalyst, instead of regenerating i.e. continuously or intermittently withdrawing, regenerating, and replacing with the regenerated catalyst that may not have as high activity and / or same selectivity as the catalyst had when fresh.

[0034] In the present process, in step d) at least a portion of the first hydroconversion stage effluent and the renewable feed are subjected to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a second hydroconversion stage effluent. In certain preferred embodiments, in step d) the second hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a fixed bed and / or in a moving catalyst bed, preferably at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, wherein the moving catalyst bed is preferably an ebullated bed. Regarding the selection of the hydrotreatment catalyst(s) for each hydroconversion zone of step d), similar considerations may apply as explained in connection with the hydroconversion zones of step c). When entering the second hydroconversion stage, the heavy crude oil feed has already been converted to such an extent that using fixed bed systems for the hydroconversion is getting more attractive. However, due to the numerous benefits of moving catalyst bed systems as explained in the foregoing, those may be preferred also in the second hydroconversion stage.

[0035] In certain embodiments, the hydrotreatment catalyst in step c) and / or step d) includes one or more hydrotreatment catalysts selected independently for each hydroconversion zone from sulfided hydrotreatment catalysts comprising 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. This kind of solid heterogeneous hydrotreatment catalysts are commercially available for use in ebullated bed and fixed bed hydroconversion systems, including catalysts designed primarily for certain hydrotreatment reactions such as hydrodemetallization, and / or even for hydrocracking. In addition to the hydrotreatment catalyst(s), also co-catalysts may be utilised in step c) and / or step d) to achieve additional reactions and / or to boost any of the hydrotreatment reactions, as known in the art. The heterogeneous hydrotreatment catalyst typically comprises a support structure having a large surface area and interconnected channels or pores and the active metal(s), such as sulfides of cobalt, nickel, tungsten, and / or molybdenum, e.g. dispersed within the channels or pores. The pores of the support may be of limited size to maintain mechanical integrity of the heterogeneous catalyst and prevent breakdown and formation of excessive fines in the reactor. Heterogeneous catalysts usable in the present process may have a shape of cylindrical pellets, cylindrical extrudates, trilobes, rings, saddles, spherical solids, or the like. Also dispersed metal sulfide catalysts may be used in the present process. These catalysts have typically a submicron particle size (below 1 pm), such as less than about 500 nm, or even less than about 50 nm. These catalysts may also include molecular or molecularly- dispersed catalyst compounds. In certain preferred embodiments, each hydroconversion zone in step c) and step d) is operated at a temperature (as determined at the zone inlet), selected independently from each other, within a range from 350 °C to 480 °C, preferably from 370 °C to 460 °C. Within these temperature ranges thermal cracking is abundant, and catalytic heteroatom removal and hydrogenation of any present or formed olefins are enhanced. In certain preferred embodiments, each hydroconversion zone in step c) and step d) is operated at a pressure (as determined at the zone outlet), selected independently from each other, within a range from 8 MPa to 20 MPa, preferably from 10 MPa to 20 MPa. Within the specified elevated pressure ranges, sufficient hydrogen partial pressure may be ensured and residual olefins and heteroatoms minimised in the hydroconversion products despite the significant hydrogen consumption and the formed gaseous cracking products reducing the H2 partial pressure towards the end of the stage or zone, whether after the last hydrogen injection point or between injection points. In certain embodiments, each hydroconversion zone in step c) and step d) is operated using a space velocity, selected independently from each other, within a range from 0.05 to 5, preferably from 0.1 to 2 m3 feed entering said zone per m3 reaction space per hour, and / or a ratio of H2 to the feed entering said zone, selected independently from each other, within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter feed. Regarding the space velocity, for fixed beds this may be expressed as volume of the liquid feed entering the zone per volume of the catalyst per hour, however the above-mentioned numerical ranges for the space velocity still apply. Regarding hydroconversion zones wherein the hydrotreatment catalyst is arranged in a moving catalyst bed, such as an ebullated bed, the catalyst loading and fresh catalyst addition rate shall be selected so that the catalyst activity may be maintained essentially constant. Adjusting these process conditions as specified herein further enhances reaching the desired conversion level, yields and / or product fraction properties.

[0036] In the present process, a heavy crude oil feed is used. Typically, heavy crude oil feeds contain heavier molecules compared to the renewable feeds, and these heavier molecules may also be thermodynamically easier to crack. This is believed to contribute to the lower than expected cracking level of the renewable feed molecules, which helps to enrich the biogenic carbon content in the middle distillates and lighter boiling liquids, without excessive over-cracking to gases.

[0037] In certain embodiments, the heavy crude oil feed comprises at least one or more of crude oil distillation residue(s) and / or crude oil heavy vacuum distillate(s), optionally as solvent deasphalted (SDA). The present process allows using low quality crude oil materials, such as crude oil distillation residue(s), for example crude oil atmospheric residue or even crude oil vacuum residue, and / or crude oil heavy vacuum d isti llate(s), which is beneficial for the process economy.

[0038] In certain preferred embodiments, the heavy crude oil feed has a carbon residue content of at least 5.0 wt.-%, such as from 5.0 wt.-% to 25.0 wt.-% or from 5.0 wt.-% to 20.0 wt.-%, preferably at least 8.0 wt.-%, such as from 8.0 wt.-% to 20.0 wt.-%, more preferably at least 10.0 wt.-%, such as from 10.0 wt.-% to 20.0 wt.-% (EN ISO 10370-2014), based on the heavy crude oil feed weight. Typically, carbon residue content is associated with content and / or formation of asphaltenes and / or carbonaceous deposits.

[0039] In embodiments where the heavy crude oil feed has not been subjected to deasphalting at all, or only a portion thereof has been deasphalted, the content of species prone to sediment formation may increase to a level inducing aggregation. Hence, in these embodiments utilising a renewable co-feed is foreseen even more advantageous. By subjecting at least part of the crude oil distillation residue(s), particularly the crude oil vacuum residue, to solvent deasphalting (SDA) reducing content of asphaltenes, sulphur and other impurities, lower quality heavy crude oil feeds may be utilised, or heavy fraction(s), even heavy separation stage bottom, of higher quality, e.g. with lower sulphur contents, may be obtained. Hence, in certain embodiments, step b) comprises subjecting a first portion of a crude oil vacuum residue to solvent deasphalting to obtain a deasphalted oil (DAO) and an asphaltenes fraction, and in step c) the deasphalted oil (DAO) and a second portion of the crude oil vacuum residue are fed as the heavy crude oil feed to the hydroconversion, preferably the weight ratio of the DAO to the second portion of the crude oil vacuum residue ranging from 90:10 to 20:80, more preferably from 80:20 to 30:70.

[0040] In certain typical embodiments, the heavy crude oil feed comprises at least 50 wt.-%, preferably at least 60 wt.-%, more preferably at least 70 wt.-% of compounds boiling above 565°C (EN 15199-2:2020), based on the total heavy crude oil feed weight. In certain typical embodiments, the heavy crude oil feed has a density at 15°C within a range from 900 kg / m3 to 1150 kg / m3 (EN ISO 12185-1996), preferably within a range from 920 kg / m3 to 1100 kg / m3, more preferably within a range from 950 kg / m3 to 1050 kg / m3. In certain typical embodiments, the heavy crude oil feed has a viscosity at 135°C within a range from 20 mm2 / s to 200 mm2 / s (EN 12595-2023), preferably within a range from 40 mm2 / s to 180 mm2 / s, more preferably within a range from 50 mm2 / s to 160 mm2 / s. Also other crude oil feeds may be co-fed to step c). Preferably, the heavy crude oil feed constitutes at least 25 wt.-%, preferably at least 50 wt.-%, more preferably at least 75 wt.- %, of the total crude oil feed(s) subjected to the hydroconversion in step c). In certain particularly preferred embodiments, the heavy crude oil feed constitutes about 100 wt.-% of the total crude oil feed(s) subjected to the hydroconversion in step c).

[0041] In certain further preferred embodiments, the heavy crude oil feed has a sulphur content of more than 1 .0 wt.-%, preferably at least 1 .2 wt.-%, such as within a range from 1 .2 wt.-% to 6.0 wt.-%, more preferably at least 1.5 wt.-%, such as within a range from 1.5 wt.-% to 4.0 wt.-% (EN ISO 8754-2003), based on the total heavy crude oil feed weight.

[0042] In the present process, a renewable feed comprising at least one or more of plant oil(s), animal fat(s), and / or microbial oil(s) is utilised. All these may contain mono-, di-, and / or triglycerides, and have similar oxygen contents, typically from 5 to 20 wt.-%, which is believed to contribute to the reduced blend sediment content and formation. Upon hydroconversion, the plant oil, animal fat, and / or microbial oil originating moieties are believed to form paraffins, predominantly in the middle distillates boiling range, thereby beneficially contributing to the processability of the recovered distillate(s) e.g. in further catalytic conversion, for example using fixed bed reactor(s).

[0043] In certain preferred embodiments, the renewable feed comprises plant oil(s) selected from 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, corn oil, castor oil, jatropha oil, pongamia 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 campestris oil, Brassica hirta seed oil and / or Brassica alba seed oil, rice bran oil, coffee oil, palm olein, palm stearin, palm fatty acid distillate (PFAD), palm oil mill effluent (POME) distillate, tall oil crude fatty acids, tall oil fatty acids (TOFA), tall oil heads, plant oleoresins such as turpentine, and / or used cooking oils of vegetable origin; animal fat(s) selected from tallow, lard, yellow grease, brown grease, fish fat, poultry fat, and / or used cooking oil of animal origin; and / or microbial oil(s) selected from algal lipids, fungal lipids, and / or bacterial lipids.

[0044] Especially plant oils(s) and / or animal fat(s) may also contain residual plastics. For example, in meat processing plants and the rendering of tallow, animal carcasses and packaged goods may be wrapped in plastic films, some of which may end up in the rendered fats. Two common plastic films are polyethylene (PE) and polyvinylidene chloride (PVDC). Plastics may end up in rendered fats also when packaged meats are recycled. The polymeric materials and associated additives may be present e.g. as particulate and / or solubilized material. Similarly, waste plant oils may also become contaminated by plastic packaging materials, disposable gloves and similar. While various pretreatment steps may reduce particulate and even solubilized material to some degree, the solubilized polymeric adulterant may still persist in the material, and as in any pretreatment, also losses of the valuable raw material may occur. However, as the present process is capable of converting the heavy crude oil feed, it is also foreseen capable of handling oils and fats contaminated with plastics. Hence, in certain preferred embodiments, the renewable feed comprises at least one or more of plant oil(s) and / or animal fat(s).

[0045] Similarly, the present process is far less sensitive to renewable feeds having elevated nitrogen content, for example compared to conventional HVO processes. E.g. animal fat(s) are known to have higher nitrogen contents compared to typical plant oils. Hence, in certain preferred embodiments, the renewable feed comprises at least animal fat(s).

[0046] In certain preferred embodiments, the renewable feed contains esters, preferably glycerides, at least 30 wt.-%, preferably at least 50 wt.-%, more preferably at least 75 wt.- % of the total weight of the renewable feed. Fats in alkylester, mono-, di- and triglyceridic forms are preferred as having lower acidity compared to free fatty acids. High acidity (total acid number, TAN), on the other hand, may involve corrosion concerns depending on the metallurgy of the used equipment, and may also increase risk of residual acidity being present in the recovered products. Hence, in certain preferred embodiments, the renewable feed has a total acid number (TAN) less than 10 mg KOH / g, preferably less than 7.0 mg KOH / g, more preferably less than 5.0 mg KOH / g (ISO 660-2020).

[0047] If the renewable feed(s) contain amounts or species of impurities that are not tolerated or preferred in the hydroconversion or that may slip through downstream to the detriment of the heavy separation stage bottom and / or the one or more distillate(s) in view of their intended uses, the content of said impurities may be reduced to acceptable limits using pretreatment methods known in the art. Exemplary pretreatment 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. In the context of the present process, the renewable feeds listed in step a) refer to these materials in their as-is or pretreated forms, as the case may be.

[0048] In certain embodiments, in step d) the renewable feed and the at least a portion of the first hydroconversion stage effluent are fed to the hydroconversion within a weight-ratio of the renewable feed to the at least a portion of the first hydroconversion stage effluent from 1 :99 to 80:20, preferably from 3:97 to 80:20 or from 3:97 to 50:50, more preferably from 5:95 to 50:50 or from 5:95 to 30:70. Within these ratios a heavy separation stage bottom exhibiting an enhanced sediment reducing effect may be attained, while still producing it in reasonable amounts.

[0049] In certain preferred embodiments, the process further comprises f) subjecting at least a portion of the distillate(s) recovered in step e) to one or more further conversion step(s), such as to one or more catalytic conversion step(s), preferably to one or more catalytic hydroprocessing step(s). The catalytic hydroprocessing step(s) are not particularly limited and may comprise for example catalytic hydrotreatment, catalytic hydrocracking, catalytic hydroisomerisation, and / or catalytic hydrodearomatisation. In certain particularly preferred embodiments, at least a portion of the d istil late(s) recovered in step e) is subjected to one or more catalytic hydroprocessing step(s) comprising at least one or more of a fixed bed catalytic hydrotreatment, a fixed bed catalytic hydrocracking, a fixed bed catalytic hydroisomerisation, and / or a fixed bed catalytic hydrodearomatisation, further preferably to one or more catalytic hydroprocessing step(s) comprising one or more optional fixed bed catalytic hydrotreatment step(s) followed by one or more fixed bed catalytic hydrocracking step(s) and one or more fixed bed catalytic hydroisomerisation step(s). Between any two or more of the further conversion steps, separation and / or fractionation may be conducted, so that only a portion of the effluent of a preceding conversion step continues to the subsequent conversion step. Thanks to the enhanced purity and elevated paraffins content of the distillates, particularly of the middle distillate fraction(s) such as diesel range fraction, catalytic upgrading thereof is foreseen easier e.g. in terms of less severe process conditions, slower catalyst deactivation, reduced coking and plugging. Consequently, fixed bed reactors may be utilised in the upgrading. Hydroprocessing step(s), such as hydrotreatment, hydrocracking, hydroisomerisation, and / or hydrodearomatisation, are especially advantageous as high-quality aviation fuel components, diesel components and / or solvents are attainable with good cold properties and / or reduced aromatics contents. In certain embodiments, the first hydroconversion stage effluent obtained in step c) is subjected to an interstage separation to obtain a volatiles fraction and a non-volatiles fraction, and the non-volatiles fraction is fed to the second hydroconversion stage in step d). In certain preferred embodiments, at least a portion of the volatiles fraction is fed with the second hydroconversion stage effluent to the separation stage in step e), and / or at least a portion of the volatiles fraction is fed to one or more further conversion step(s), preferably to one or more catalytic conversion step(s), more preferably to one or more catalytic hydroprocessing step(s), optionally with the at least a portion of the distillate(s) in step f) described in the foregoing.

[0050] In certain embodiments, the volatiles fraction comprises at least compounds boiling below 300 °C at atmospheric pressure, and the non-volatiles fraction comprises at least compounds boiling above 300 °C at atmospheric pressure.

[0051] Having an interstage separation may provide several advantages. By removing a volatiles fraction, smaller equipment may suffice in the second hydroconversion stage. Alternatively, a higher (full) capacity is available in the second hydroconversion stage for converting the remaining heavy components, due to the reduced vapour load. The reduced vapour load enhances hydrogen purity and allows a higher hydrogen partial pressure in the second hydroconversion stage, thereby enhancing catalytic reactions so that the recovered fractions are purer and contain less olefins. Also, less pentane, heptane and similar saturated light compounds, that are poor solvents for asphaltenes, enter the second hydroconversion stage, thereby reducing the risk of precipitate formation. On the other hand, in embodiments where only the non-volatiles fraction continues to the second hydroconversion stage, the content of species prone to sediment formation may increase to a level inducing aggregation. Hence, in these embodiments utilising the renewable feed provided in step a) is even more advantageous, and / or a heavy crude oil feed whereof at least a portion has been subjected to deasphalting.

[0052] In the separation stage any separation technologies well known in the field of hydrocarbon fractionation, such as in petroleum refining and / or HVO technology, may be utilised. The separation stage may be carried out in a separation stage system comprising separation and / or fractionation units. For example, at least part of gaseous components may be separated in gas-liquid separator(s), whereafter other separation and / or fractionation unit(s) may follow. Separation unit(s) may be included e.g. to attain stabilisation which is one type of partial distillation for removing gaseous and most volatile liquid hydrocarbons to reduce vapour pressure, and which may be conducted for example using stripper(s) or distillation column(s). For fractionation for example distillation column(s) and / or evaporator(s) may be included. The one or more distillates such as a naphtha fraction, a diesel range fraction, a light vacuum gas oil fraction, and / or a heavy vacuum gas oil fraction, and the heavy separation stage bottom, may be recovered e.g. using one or more distillation unit(s) and / or evaporation unit(s). The distillation and / or evaporation unit(s) may comprise atmospheric distillation and / or evaporation unit(s), and / or vacuum distillation and / or evaporation unit(s).

[0053] In certain preferred embodiments, the one or more distillate(s) recovered in step e) have T90 temperature (90 wt.-% recovered, ASTM D2887-2023) less than 500°C, preferably less than 480°C. The biogenic carbon content provided by the renewable feed may reside essentially completely in this boiling point range. In certain preferred embodiments, the one or more distillate(s) include one or more middle distillate fraction(s) having T10 and T90 temperatures (10 wt.-% and 90 wt.-% recovered, respectively, ASTM D2887-2023) within a range from 130°C to 430°C, preferably from 140°C to 420°C. The biogenic carbon content provided by the renewable feed is effectively enriched in the middle distillates boiling point range. In certain preferred embodiments, the one or more distillate(s) include one or more naphtha fraction(s) having T90 temperature (90 wt.-% recovered, ASTM D7096-2019) of at most 200°C and one or more middle distillate fraction(s) having T10 and T90 temperatures (10 wt.-% and 90 wt.-% recovered, respectively, ASTM D2887-2023) within a range from 140°C to 380°C, and optionally a vacuum gas oil fraction having T10 temperature (10 wt.- % recovered, ASTM D2887-2023) of at least 330°C, preferably a light vacuum gas oil fraction having T10 and T90 temperatures (10 wt.-% and 90 wt.-% recovered, respectively, ASTM D2887-2023) within a range from 330°C to 480°C. Recovering several different and hence narrower boiling fractions provides biogenic carbon containing feeds optimal for further conversion step(s) aiming at different high value products.

[0054] In certain embodiments, the heavy separation stage bottom, preferably the heavy vacuum tower bottom, recovered in step e) has T10 temperature (10 wt.-% recovered, EN15199- 2:2020) of at least 380°C, preferably at least 420°C, more preferably at least 450°C. When the heavy separation stage bottom is recovered in this way, more of the valuable lighter hydrocarbons may be recovered in a lower boiling fraction, such as in a vacuum gas oil fraction, usable in a wider range of applications than the heavy separation stage bottom. In certain preferred embodiments, the heavy separation stage bottom, preferably the heavy vacuum tower bottom, recovered in step e) has T10 temperature (10 wt.-% recovered, EN 15199-2:2020) within a range from 3800°C to 600°C, preferably from 420°C to 600°C, more preferably from 450°C to 600°C. In this way the quality and / or blending ratio of the heavy separation stage bottom in marine fuels may be enhanced.

[0055] In certain preferred embodiments, the heavy separation stage bottom, preferably the heavy vacuum tower bottom, recovered in step e) has one or more of the following: a biogenic carbon content, preferably a biogenic carbon content of at least 0.1 wt.-%, based on the total weight of carbon (TC) in the separation stage bottom (ASTM D6866-2022); a density at 15°C within a range from 850 kg / m3 to 1060 kg / m3, preferably from 900 kg / m3 to 1030 kg / m3 (EN ISO 12185-1996); a viscosity at 80°C at least 30 mm2 / s, preferably at least 40 mm2 / s, more preferably at least 50 mm2 / s (EN 12595-2023), and a viscosity at 135°C at most 170 mm2 / s (EN 12595-2023); a total content of sulphur at most 1 .5 wt.-%, preferably at most 1.0 wt.-% (ASTM D7039-15a(2020)); and / or a total content of compounds boiling below 560°C (EN 15199-2:2020) less than 35 wt.-%, preferably less than 25 wt.-%. All these properties of the heavy separation stage bottom are advantageous for use in marine fuels, and attainable by the present process.

[0056] In certain preferred embodiments, the process further comprises incorporating at least a portion of the heavy separation stage bottom recovered in step e) into a marine fuel pool, preferably into a residual marine fuel pool.

[0057] According to the present disclosure, there is also provided use of a heavy separation stage bottom, such as a vacuum tower bottom, obtainable by the process according to the first example aspect, as a blend component in a marine fuel, especially in a residual marine fuel meeting one or more characteristics laid down in ISO 8217-2017 Table 2, preferably in an amount of 1 vol-% to 90 vol-% based on the marine fuel volume, wherein the heavy separation stage bottom preferably has T10 temperature (10 wt.-% recovered, EN15199- 2:2020) of at least 380°C, preferably at least 420°C, more preferably at least 450°C, preferably within a range from 380°C to 600°C, more preferably from 420°C to 600°C, even more preferably from 450°C to 600°C.

[0058] Schematic presentation of the process

[0059] Fig. 1 schematically shows a process according to an example embodiment. In the process shown in Fig. 1 , a renewable feed R comprising at least one or more of plant oil(s), animal fat(s) and / or microbial oil(s), and a heavy crude oil feed HCO comprising for example at least one or more of crude oil distillation residue(s) and / or crude oil heavy vacuum distillate(s), optionally as solvent deasphalted (SDA), are provided. The heavy crude oil feed HCO is subjected to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage 100 to obtain a first hydroconversion stage effluent 10. Preferably the first hydroconversion stage comprises at least two hydroconversion zones in series each containing the hydrotreatment catalyst arranged in a moving catalyst bed, preferably in an ebullated bed. The first hydroconversion stage effluent 10 may be subjected to an interstage separation 150 to obtain a volatiles fraction 15 and a non-volatiles fraction 20. The first hydroconversion stage effluent 10 or a portion thereof, such as the non-volatiles fraction 20, is then subjected together with the renewable feed R to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage to obtain a second hydroconversion stage effluent 30. Preferably the second hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a fixed bed or a moving catalyst bed, more preferably at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, particularly in an ebullated bed. The second hydroconversion stage effluent 30, optionally together with at least a portion of the volatiles fraction 15, is then fed to a separation stage 300. From the separation stage 300 at least a heavy separation stage bottom 40, such as a heavy vacuum tower bottom, and one or more distillate(s) 50, such as atmospheric and / or light vacuum distillate(s), are recovered. The heavy separation stage bottom 40 is usable as a marine fuel component. In preferred embodiments, at least a portion of the distillate(s) 50 is subjected to one or more further conversion step(s) 400, 600, preferably to one or more catalytic conversion step(s), more preferably to one or more catalytic hydroprocessing step(s). In certain particularly preferred embodiments, at least a portion of the distillate(s) 50 is subjected to catalytic hydrotreatment 400 to obtain a hydrotreatment effluent 60, followed by further separation stage 500 to recover one or more hydrotreatment d istil late(s) 80, a hydrotreatment bottom 70, and a hydrotreatment overhead 65, and subjecting at least a portion of the hydrotreatment distillate(s) 80 and / or of the hydrotreatment bottom 70 to a catalytic hydroisomerisation and / or catalytic hydrocracking 600, preferably in fixed bed(s), to provide fraction(s) 90 with enhanced properties, particularly cold properties, compared to the properties of the hydrotreatment distillate(s) 80 and / or the hydrotreatment bottom 70, respectively.

[0060] EXAMPLES

[0061] Example 1. Heavy crude oil and renewable oil feeds Animal fat was pretreated in a conventional manner by heat-treatment and bleaching to provide purified animal fat (AF) as the renewable feed for use in the test runs. Content of certain heteroatoms and acidity were measured from the purified animal fat and are reported in Table 1. Additionally, the fatty acid composition (after hydrolysis) of a representative purified animal fat was determined by ISO 12966-4:2015 and is reported in

[0062] Table 2, together with fatty acid compositions of certain other renewable feeds, for assessing their suitability for use in the present process.

[0063] Table 1. Content of certain heteroatoms and acidity of the purified animal fat used in the test runs. As can be seen from Table 1 , the purified animal fat had low acidity and sulphur contents, moderate nitrogen content and significant oxygen content, typical for fatty materials.

[0064] Table 2. Fatty acid composition (wt.-%) of a purified animal fat representative of what was used in the test runs, and exemplary fatty acid compositions* (wt.-%) of certain other renewable oils.

[0065] * Source: The Lipid Handbook, 2nd edition, eds Gunstone, Harwood and Padley, Chapman & Hall (1986), pages 90, 116, 157, 206, and 207; except for tall oil fatty acids fraction (TOFA): Naval Stores, eds. Zinkel and Russell, Pulp Chemicals Association, Inc (1989), page 362

[0066] # Exemplary ranges for some marine phytoplankton, marine macroalgae, and freshwater and salt- tolerant species

[0067] As can be seen from Table 2, different animal fats have very similar fatty acid profiles regardless of the origin. Also Cyanobacteria have quite similar fatty acid profiles, as well as typical algal oils, although certain algae species may additionally have high content of C20- C22 multi-unsaturated fatty acids. The exemplary non-edible plant oils, namely Pongamia seed oil, Brassica campestris seed oil, Brassica napus seed oil, and TOFA, have somewhat heavier fatty acid profiles, TOFA additionally containing up to about 10 wt.-% of resin acids and / or neutrals. Due to the similarities of these fats and oils with the animal fat used in the test runs, especially the high fatty acid compositions and hence similar total oxygen contents, all these oils and fats are foreseen suitable as the renewable feed for use in the present process.

[0068] Heavy crude oil feeds were prepared as follows. A portion of crude oil vacuum residue (VR) was subjected to a conventional solvent deasphalting (SDA) to provide a deasphalted oil (in the following referred to as DAO) and an asphaltenes fraction. A portion of the DAO and another portion of the crude oil VR were then blended 50:50 (weight:weight) to obtain a heavy crude oil feed referred to as DAO / VR in the following. Certain properties of DAO and DAO / VR were analysed and are reported in Table 3.

[0069] Table 3. Certain properties of DAO and DAO / VR.

[0070] * Inductively coupled plasma tandem mass spectrometer method for trace level elements from microwave digestion pretreated samples

[0071] As can be seen from Table 3, DAO is a bit less viscous compared to the DAO / VR 50:50 blend, and has a lower content of heptane and pentane insolubles, reflecting its lower asphaltenes content. Also the total content of Na, V, Fe, and Ni is much lower. Common characteristics include high density and initial boiling point, high content of unsaturated compounds generally and aromatics specifically, as well as high sulphur and nitrogen contents. In other words, these heavy crude oil feeds are among the least valuable crude oil fractions, and require extensive processing e.g. at severe process conditions and / or in multiple steps to upgrade them to lower boiling products having higher value. Exemplary upgrading processes include those using plurality of ebullated bed reactors, for example as arranged in US2021371762 Figures 2C and 2D.

[0072] Example 2. Test runs and yields of the product fractions

[0073] For the test runs, a pilot system comprising two consecutive ebullated bed reactors in the first hydroconversion stage and one ebullated bed reactor in the second hydroconversion stage was utilised. The pilot systems were equipped with an interstage separation (ISS) arranged between the first and the second hydroconversion stage (between the second and the last reactor, similarly as shown in US2021371762 Figure 2D) to flash away a volatiles fraction, providing a non-volatiles fraction which continued to the second hydroconversion stage. The reactors were arranged with a sulphided non-noble metal hydrotreatment catalyst (NiMo on alumina) suitable for use in ebullated beds. Unlike in commercial scale ebullated bed systems, for simplicity the catalyst was not renewed in the pilot systems. This may have had a somewhat negative influence on the results, e.g. lesser conversion of more persistent species due to the reduced catalyst activity towards the end of the test runs. Consequently, the advantages observed in these pilot test runs are even more significant.

[0074] The test runs were conducted at stable conditions with a target resid conversion of about 70-75 wt%. The temperature in each reactor was about 410°C, and pressure about 165 bar. DAO and DAO / VR feeds as prepared in Example 1 were fed as the heavy crude oil feeds to the first reactor at a rate of 97 g / h. Hydrogen was fed at a rate of 79 l / l of feed per hour split into the three reactors in a volume ratio of 40:20:40. In the test runs according to the present disclosure, the purified animal fat (AF) as prepared in Example 1 was co-fed to the second hydroconversion stage together with the non-volatile fraction of the first hydroconversion stage effluent in an amount of 15 wt.-%, based on the weight of the feed to the first hydroconversion stage.

[0075] In the test runs the first hydroconversion stage effluent was fed to the ISS, operated at ~340°C, to flash off volatiles fraction, thereby providing a non-volatiles fraction that was cofed together with the purified animal fat to the second hydroconversion stage. In the first set of test runs the volatiles fraction was not fed to the separation stage, and is hence excluded from the liquid product yields reported in Table 4. In the second set of test runs the volatiles fraction was co-fed with the second hydroconversion stage effluent (i.e. effluent from the last hydroconversion zone) to the separation stage, and is included in the liquid product yields reported in Table 5.

[0076] In the test runs the separation stage comprised a gas-liquid separator and batch distillation to recover a gaseous overhead, naphtha (targeted boiling point range: IBP-200°C) and diesel range (targeted boiling point range: 200-360°C) fractions, whereafter the bottom of the batch distillation was further distilled continuously in a short path evaporator (SPE) to recover light vacuum gas oil (LVGO, targeted boiling point range: 360-480°C), heavy vacuum gas oil (HVGO, targeted boiling point range: 480-560°C) and heavy vacuum tower bottom (heavy VTB, targeted boiling point range: 560°C+) fractions. The liquid product fraction yields are reported in Table 4 for test runs without feeding the volatiles fraction separated in the ISS to the separation stage, and in Table A5 for test runs where the volatiles fraction separated in the ISS was co-fed to the separation stage. Also the naphtha, diesel, LVGO, HVGO and heavy VTB amounts in the heavy petroleum feeds as fed in the reference test runs to the first hydroconversion stage and thereafter i.e. as fed to the second hydroconversion stage, are reported for comparison. Table 4. Naphtha, diesel, LVGO, HVGO and heavy VTB amounts in the heavy petroleum feed before the first hydroconversion stage and thereafter i.e. as fed to the second hydroconversion stage, and as yielded as liquid product fractions from the reference test runs and from the test runs according to the present process. ISS was arranged between the first and the second hydroconversion stage, but the volatiles fraction was not co-fed to the separation stage.

[0077] * Excluding the volatiles fraction separated in the ISS, and reported as normalised to 100%. The actual liquid yield of the first hydroconversion stage is about 84 wt.-% for both DAO and DAO / VR. In Table 4, the combined yields of product fractions from naphtha to VTB fraction were about

[0078] 95 wt.-%, the balance being gaseous products (not reported in Table 4). Table 4 illustrates how the heavy crude oil feeds “DAO feed” and “DAO / VR feed” get converted in the first hydroconversion stage (DAO and DAO / VR after 1st hydroconversion stage), and in the second hydroconversion stage (Product fractions from DAO and DAO / VR test run). In the first hydroconversion stage, the heaviest (HVGO and VTB range) hydrocarbons are reduced from ~99wt.-% significantly, while especially diesel and LVGO range hydrocarbons are being formed. However, the second hydroconversion stage is still required to reduce the heaviest hydrocarbons further, and to increase diesel range hydrocarbons further. At the same time metals are captured by the catalyst and heteroatoms cleaved.

[0079] As can be seen from the Table above, co-feeding 15 wt.-% animal fat to the second hydroconversion stage increased the combined yield of naphtha, diesel range and LVGO fractions by 17% when co-processing with the slightly lighter DAO, and by 9.8% when coprocessing with the heavier DAO / VR, compared to the corresponding reference test run with DAO or DAO / VR alone. The yield of the most valuable hydrocarbons, namely diesel range fraction, increased by over 75%, and by 48%, respectively (compared to the corresponding reference test run with DAO or DAO / VR alone). It is well known e.g. from conventional HVO process, that hydrodeoxygenating animal fat to n-paraffins is rather easy, i.e. using much lower temperature and pressure conditions, so there was an expectation of overcracking the readily formed n-paraffins to naphtha and gas range products in the second hydroconversion stage. Surprisingly this was not the case based on the fraction yields, but the carbon chains of the animal fat molecules mainly remained in the diesel range, despite the second hydroconversion being run at severe conditions that are needed to ensure sufficient conversion and impurity removal of the heavy crude oil feed. The test run results revealed also a significant decrease in the combined yield of less valuable heavy hydrocarbons, namely heavy VGO and VTB fractions, compared to the corresponding reference test run with DAO or DAO / VR alone.

[0080] Table 5. Naphtha, diesel, LVGO, HVGO and heavy VTB amounts as yielded as liquid product fractions from the reference test runs and from the test runs according to the present process. An ISS was arranged between the first and second hydroconversion stage, and the volatiles fraction was co-fed to the separation stage.

[0081] In these test runs the volatiles fraction separated in the ISS was co-fed with the second hydrotreatment stage effluent to the same separation stage i.e. it is included in the yields reported in Table 5. The combined yields of liquid product fractions from naphtha to VTB fraction were about 82 wt.-%, the balance being gaseous products.

[0082] Regarding the effect of co-feeding 15 wt.-% animal fat to the second hydroconversion stage, the results reported in Table 5 reveal a significant increase in the combined yield of naphtha, diesel range and LVGO fractions, 11-13% (compared to the corresponding reference test run with DAO or DAO / VR alone), whether co-processing with the slightly lighter DAO or with the heavier DAO / VR. The yield of the most valuable hydrocarbons, namely diesel range fraction, increased by 44-45%, respectively (compared to the corresponding reference test run with DAO or DAO / VR alone). Similarly as in the test runs reported in Table 4, also here the carbon chains of the animal fat molecules mostly remained in the diesel range. Also in these test runs a significant decrease in the combined yield of less valuable heavy hydrocarbons, namely heavy VGO and VTB fractions, was observed, compared to the corresponding reference test run with DAO or DAO / VR alone.

[0083] Example 3. Certain properties of the distillates recovered from the test runs

[0084] In the following are reported certain properties analysed from the naphtha, diesel range, light vacuum gas oil (LVGO), and heavy vacuum gas oil (HVGO) fractions recovered from the test runs reported in Example 2 Table 5.

[0085] All the recovered naphtha fractions had similar T5 and T95 temperatures (5 wt.-% and 95 wt.-% recovered by ASTM D7096-2019, 60°C and 215°C, respectively), as well as contents of paraffins (~45wt.-%), naphthenes (25-28 wt.-%), and aromatics (15-20 wt.-%). Contents of olefins, oxygenates, dienes and heterocompounds were below detection limit (<0.01 wt.- %) in all naphtha fractions. Generally, the main difference between the naphtha fractions recovered from the present process and the naphtha fractions from the corresponding reference test run appeared to be the biogenic carbon content, 3 wt.-% in the test runs with AF and DAO, and 6 wt.-% in the test runs with AF and DAO / VR, based on the total weight of carbon in the naphtha fraction (ASTM D6866-2022), with a minor increase in the n- paraffins content.

[0086] Certain properties of the diesel range fractions are reported in Table 6 below. The diesel range fractions were very similar based on their simulated distillation results, but differed in many other respects significantly. Most importantly, the biogenic carbon content from the AF-containing test runs with DAO and DAO / VR were 42 and 44wt-%, based on the weight of total carbon in the diesel range fraction (ASTM D6866-2022), respectively. The high share of animal fat originating content led to higher n-paraffins content (not reported in Table 6) and hence poorer cloud point and pour point. At the same time the share of monoaromatics was reduced by at least 40%. Consequently, the densities of the diesel range fractions from the present process were decreased. What is most surprising in the diesel range fraction results, is the very high enrichment of the biogenic carbon content to this fraction, despite the severe process conditions used in the test runs, that were believed not only to hydrodeoxygenate the glycerides of the AF feed but also to crack the formed long-chained n-paraffins to lower boiling naphtha range paraffins. However, the naphtha fractions contained only 3 or 6 wt.-% biogenic carbon, based on the weight of total carbon in the naphtha fraction.

[0087] Table 6. Certain properties of the recovered diesel range fractions (200-360 °C).

[0088] All the recovered LVGO fractions had similar T5 and T95 temperatures (5 wt.-% and 95 wt.- % recovered by ASTM D2887-2023, 350°C and 495°C, respectively), density at 15°C (920 kg / m3by ENISO12185-1996) as well as content of aromatics (44-48 wt.-%). Generally, the main difference between the LVGO fractions recovered from the present process and the LVGO fraction from the corresponding reference test run appeared to be the biogenic carbon content, 2 wt.-% in the test runs with AF and DAO, and 3 wt.-% in the test runs with AF and DAO / VR, based on the total weight of carbon in the LVGO fraction (ASTM D6866- 2022), with a minor increase in the n-paraffins content.

[0089] Also all the recovered HVGO fractions had similar T5 and T95 temperatures (5 wt.-% and 95 wt.-% recovered by ASTM D2887-2023, 460°C and 565°C, respectively), as well as density at 15°C (-940 kg / m3by ENISO12185-1996). Generally, the main difference between the HVGO fractions recovered from the present process and the HVGO fraction from the corresponding reference test run appeared to be the biogenic carbon content, 1 wt.-% in the test runs with AF and DAO, and 1 wt.-% in the test runs with AF and DAO / VR, based on the total weight of carbon in the HVGO fraction (ASTM D6866-2022).

[0090] Example 4. Certain properties of the separation stage bottoms recovered from the test runs and their suitability for use in marine fuels

[0091] Certain properties of the heavy VTB fractions were analysed and compared with ISO 8217- 2017 specification requirements for RMG type residual marine fuel. The results are reported in Tables 7 and 8 below.

[0092] Table 7. Certain properties of the heavy VTB fractions recovered from the test runs reported in Example 2 Table 4, and certain ISO 8217-2017 (Table 2) specification requirements for RMG type residual marine fuel.

[0093] * Statutory requirement set by IMO (International Maritime Organisation)

[0094] Table 8. Certain properties of the heavy VTB fractions recovered from the test runs reported in Example 2 Table 5, and certain ISO 8217-2017 (Table 2) specification requirements for RMG type residual marine fuel. * Statutory requirement set by IMO (International Maritime Organisation) All the recovered heavy VTB fractions had similar T5 temperatures (5 wt.-% recovered (EN 15199-2:2020) at about 535°C, not reported in the Tables). As can be seen from Tables 7 and 8, co-feeding AF did not significantly alter the density of the heavy VTB fraction, so that the density requirement of the same residual marine fuel category was met as with the respective reference heavy VTB fraction. Also the acidity remained on a very low level. Cofeeding AF provided similar or lower sulphur contents to the heavy VTB fraction, as observed in the respective reference heavy VTB fraction. Based on the results reported in Table 7, AF co-fed with DAO / VR provided heavy VTB fraction suitable for use in RMK type residual marine fuels without blending limitations, and AF co-fed with DAO provided heavy VTB fraction suitable for use even in RMD type residual marine fuels without blending limitations. Based on the results reported in Table 8, AF co-fed with DAO / VR provided heavy VTB fraction suitable for use in RMK type residual marine fuels without blending limitations, and AF co-fed with DAO provided heavy VTB fraction suitable for use even in RMB type residual marine fuels without blending limitations. Naturally all the obtained heavy VTB fractions may also be used as components in higher quality residual marine fuels, in suitably limited shares.

[0095] Next, sediments and aged sediments of two different blend compositions were determined. In the first set of tests, 70 wt-% of the heavy VTB fractions obtained with the present process by co-feeding animal fat with DAO / VR blend were mixed with 30 wt -% of conventional petroleum-based FCC gas oil. In the second set of tests, 50 wt-% of the heavy VTB fractions obtained with the present process by co-feeding animal fat with DAO / VR blend were mixed with 8 wt-% of the HVGO obtained by the reference process having DAO / VR as feed, with 25 wt-% of conventional petroleum-based FCC atmospheric distillation bottom and with 17 wt-% of conventional petroleum-based FCC light cycle oil. The sediment tests were performed according to IS010307-1 :2009, and the aged sediment tests were performed according to 18010307-2:2009 A. The results of these tests are reported in Table 9.

[0096] Table 9. Blend sediment and blend aged sediment test results using heavy VTB from reference test run and from test run with AF.

[0097] As can be seen from Table 9, the heavy VTB fractions recovered from the present process exhibited significantly reduced sediment and aged sediment amounts, compared to the reference heavy VTBs, and in view of the aged sediment specification limit of at most 0.10 wt.-% (ISO 8217-2017 for all residual marine fuel grades). This is surprising in view of the negligent content of molecules originating from the co-fed animal fat in the heavy VTB fractions, as confirmed by the biogenic carbon content measurements. Without wishing to be bound to a theory it is believed that the presence of the polar species, especially the oxygenated hydrocarbon molecules abundant in the renewable co-feed help to keep the sediment-prone species dispersed long enough in the second hydroconversion stage, until the hydroconversion has sufficiently reduced the sedimentation-tendency of the latter. As the oxygen content of the heavy VTB fraction was essentially the same (not reported in the Tables) despite using the renewable co-feed, it may be deduced that the heteroatomspecies of the renewable co-feed do not persist but get essentially fully cleaved in the second hydroconversion stage. The present process provides significant economic advantage as the achieved low sediment contents allow the heavy separation stage bottoms to be incorporated in higher blending ratios in final marine fuel compositions, compared to otherwise similar fractions obtained without co-feeding the renewable feed to the second hydroconversion.

[0098] 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.

[0099] 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. 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 having biogenic carbon content, the process comprising: a) providing a renewable feed comprising at least one or more of plant oil(s), animal fat(s), and / or microbial oil(s); b) providing a heavy crude oil feed; c) subjecting the heavy crude oil feed to hydroconversion in the presence of a hydrotreatment catalyst in a first hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a first hydroconversion stage effluent; d) subjecting at least a portion of the first hydroconversion stage effluent and the renewable feed to hydroconversion in the presence of a hydrotreatment catalyst in a second hydroconversion stage comprising one or more hydroconversion zone(s) to obtain a second hydroconversion stage effluent; and e) feeding the second hydroconversion stage effluent to a separation stage and recovering from the separation stage at least a heavy separation stage bottom, preferably a heavy vacuum tower bottom, and one or more distillate(s).

2. The process according to claim 1 , wherein in step c) the first hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, preferably at least two hydroconversion zones in series each containing the hydrotreatment catalyst arranged in a moving catalyst bed, wherein the moving catalyst bed is preferably an ebullated bed.

3. The process according to claim 1 or 2, wherein in step d) the second hydroconversion stage comprises at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a fixed bed and / or in a moving catalyst bed, preferably at least one hydroconversion zone containing the hydrotreatment catalyst arranged in a moving catalyst bed, wherein the moving catalyst bed is preferably an ebullated bed.

4. The process according to any one of the preceding claims, wherein the hydrotreatment catalyst in step c) and / or step d) includes one or more hydrotreatment catalysts selected independently for each hydroconversion zone from sulfided hydrotreatment catalysts comprising 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 moreof 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.

5. The process according to any one of the preceding claims, wherein each hydroconversion zone in step c) and step d) is operated at a temperature (as determined at the zone inlet), selected independently from each other, within a range from 350 °C to 480 °C, preferably from 370 °C to 460 °C, and / or at a pressure (as determined at the zone outlet), selected independently from each other, within a range from 8 MPa to 20 MPa, preferably from 10 MPa to 20 MPa.

6. The process according to any one of the preceding claims, wherein the heavy crude oil feed comprises at least one or more of crude oil distillation residue(s) and / or crude oil heavy vacuum distillate(s), optionally as solvent deasphalted (SDA).

7. The process according to any one of the preceding claims, wherein the heavy crude oil feed comprises at least 50 wt.-%, preferably at least 60 wt.-%, more preferably at least 70 wt.-% of compounds boiling above 565°C (EN 15199-2:2020), based on the total heavy crude oil feed weight; wherein the heavy crude oil feed has a density at 15°C within a range from 900 kg / m3 to 1150 kg / m3 (EN ISO 12185-1996), preferably within a range from 920 kg / m3 to 1100 kg / m3, more preferably within a range from 950 kg / m3 to 1050 kg / m3; and / or wherein the heavy crude oil feed has a viscosity at 135°C within a range from 20 mm2 / s to 200 mm2 / s (EN 12595-2023), preferably within a range from 40 mm2 / s to 180 mm2 / s, more preferably within a range from 50 mm2 / s to 160 mm2 / s.

8. The process according to any one of the preceding claims, wherein the renewable feed comprises at least one or more of plant oil(s) and / or animal fat(s); preferably at least one or more plant oil(s) selected from 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, corn oil, castor oil, jatropha oil, pongamia 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 campestris oil, Brassica hirta seed oil and / or Brassica alba seed oil, rice bran oil, coffee oil, palm olein, palm stearin, palm fatty acid distillate (PFAD), palm oil mill effluent (POME) distillate, tall oil crude fatty acids, tall oil fatty acids (TOFA), tall oil heads, plant oleoresins such as turpentine, and / or used cooking oils of vegetable origin; and / or animal fat(s) selected fromtallow, lard, yellow grease, brown grease, fish fat, poultry fat, and / or used cooking oil of animal origin.

9. The process according to any one of the preceding claims, wherein the renewable feed contains esters, preferably glycerides, at least 30 wt.-%, preferably at least 50 wt.-%, more preferably at least 75 wt.-% of the total weight of the renewable feed; and / or wherein the renewable feed has a total acid number (TAN) less than 10 mg KOH / g, preferably less than 7.0 mg KOH / g, more preferably less than 5.0 mg KOH / g (ISO 660-2020).

10. The process according to any one of the preceding claims, wherein in step d) the renewable feed and the at least a portion of the first hydroconversion stage effluent are fed to the hydroconversion within a weight-ratio of the renewable feed to the at least a portion of the first hydroconversion stage effluent from 1 :99 to 80:20, preferably from 3:97 to 50:50, more preferably from 5:95 to 30:70.

11. The process according to any one of the preceding claims, wherein the first hydroconversion stage effluent obtained in step c) is subjected to an interstage separation to obtain a volatiles fraction and a non-volatiles fraction, and the non-volatiles fraction is fed to the second hydroconversion stage in step d), and preferably at least a portion of the volatiles fraction is fed with the second hydroconversion stage effluent to the separation stage in step e).

12. The process according to claim 11 , wherein the volatiles fraction comprises at least compounds boiling below 300 °C at atmospheric pressure, and the non-volatiles fraction comprises at least compounds boiling above 300 °C at atmospheric pressure.

13. The process according to any one of the preceding claims, wherein the process further comprises f) subjecting at least a portion of the distillate(s) recovered in step e) to one or more further conversion step(s), preferably to one or more catalytic hydroprocessing step(s), more preferably to one or more catalytic hydroprocessing step(s) comprising at least one or more of a fixed bed catalytic hydrotreatment, a fixed bed catalytic hydrocracking, a fixed bed catalytic hydroisomerisation, and / or a fixed bed catalytic hydrodearomatisation.

14. The process according to any one of the preceding claims, wherein the one or more distillate(s) recovered in step e) have T90 temperature (90 wt.-% recovered, ASTM D2887- 2023) less than 500°C, preferably less than 480°C; and / or include one or more middle distillate fraction(s) having T10 and T90 temperatures (10 wt.-% and 90 wt.-% recovered,respectively, ASTM D2887-2023) within a range from 130°C to 430°C, preferably from 140°C to 420°C; and / or include one or more naphtha fraction(s) having T90 temperature (90 wt.-% recovered, ASTM D7096-2019) of at most 200°C and one or more middle distillate fraction(s) having T10 and T90 temperatures (10 wt.-% and 90 wt.-% recovered, respectively, ASTM D2887-2023) within a range from 140°C to 380°C.

15. The process according to any one of the preceding claims, wherein the heavy separation stage bottom, preferably the heavy vacuum tower bottom, recovered in step e) has T10 temperature (10 wt.-% recovered, EN 15199-2:2020) of at least 380°C, preferably at least 420°C, more preferably at least 450°C.

16. The process according to any one of the preceding claims, wherein the heavy separation stage bottom, preferably the heavy vacuum tower bottom, recovered in step e) has one or more of the following: a biogenic carbon content, preferably a biogenic carbon content of at least 0.1 wt.-%, based on the total weight of carbon (TC) in the separation stage bottom (ASTM D6866-2022); a density at 15°C within a range from 850 kg / m3 to 1060 kg / m3, preferably from 900 kg / m3 to 1030 kg / m3 (EN ISO 12185-1996); a viscosity at 80°C at least 30 mm2 / s, preferably at least 40 mm2 / s, more preferably at least 50 mm2 / s (EN 12595-2023), and a viscosity at 135°C at most 170 mm2 / s (EN 12595-2023); a total content of sulphur at most 1 .5 wt.-%, preferably at most 1 .0 wt.-% (ASTM D7039-15a(2020)); and / or a total content of compounds boiling below 560°C (EN 15199-2:2020) less than 35 wt.-%, preferably less than 25 wt.-%.

17. Use of a heavy separation stage bottom, such as a vacuum tower bottom, obtainable by the process according to any one of claims 1-16, as a blend component in a marine fuel, especially in a residual marine fuel meeting one or more characteristics laid down in ISO 8217-2017 Table 2, preferably in an amount of 1 vol-% to 90 vol-% based on the marine fuel volume, wherein the heavy separation stage bottom preferably has T10 temperature (10 wt.-% recovered, EN 15199-2:2020) of at least 380°C, preferably at least 420°C, more preferably at least 450°C.

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