FI20236414A1

FI20236414A1 - A process for producing hydrocarbon fractions having sustainable content

Info

Publication number: FI20236414A1
Application number: FI20236414A
Authority: FI
Inventors: Tamer Alhalabi; Jarno KOHONEN; Ulla Kiiski; Wolter Rautelin; Alli Koskinen; Eerika Vuorio; Eetu Kari
Original assignee: Neste Oyj
Priority date: 2023-12-21
Filing date: 2023-12-21
Publication date: 2025-06-22
Also published as: WO2025133468A1

Abstract

A process for producing hydrocarbon fractions having renewable and/or circular content is provided. In the process, a hydrotreatment feed having petroleum content as well as renewable and/or circular content is subjected to hydrotreatment (200) to obtain a hydrotreatment effluent from which at least a naphtha fraction (410), a first middle distillate fraction (430), a second middle distillate fraction (440), and a first separation stage bottom (420) are recovered. A hydroisomerisation feed comprising at least a portion of the first or the second middle distillate fraction (430,440) is subjected to hydroisomerisation (500) to obtain a hydroisomerisation effluent from which at least one or more aviation fuel range fraction (610) and/or diesel fuel range fraction (620) is/are recovered.

Description

A PROCESS FOR PRODUCING HYDROCARBON FRACTIONS HAVING

SUSTAINABLE CONTENT

TECHNICAL FIELD

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 one or more aviation and/or diesel fuel range fraction(s), and middle distillate fraction(s) usable in aviation and/or diesel fuel range pool(s).

BACKGROUND

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

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.

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.

N

S Due to the disadvantages of the first-generation biofuels, alternative biofuels technologies a 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

N

- existing petroleum refineries has a growing interest not least because of the existing

E 25 infrastructure, which allows instant implementation and reduced investment costs. One of

J the most studied technologies for co-processing concepts is fluid catalytic cracking (FCC), + © which is a widely used process in petroleum refineries for converting heavy fractions of

N

I 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.

SUMMARY

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. A further aim is to improve the yield of middle distillates having sustainable i.e. renewable and/or circular content, especially middle distillate fraction(s) boiling within an aviation fuel range. Yet a further aim is to control or even improve the cold properties of middle distillates having sustainable content.

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. = According to a first example aspect, there is provided a process for producing hydrocarbon fractions, the process comprising: a) providing 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 first separation stage, n and recovering from the first separation stage at least a naphtha fraction, a first middle

N distillate fraction, a second middle distillate fraction, and a first separation stage bottom,

N cy wherein the first middle distillate fraction is a lower boiling middle distillate fraction and the i 25 second middle distillate fraction is a higher boiling middle distillate fraction,

N

I d) subjecting a hydroisomerisation feed comprising at least a portion of the first or the > second middle distillate fraction to hydroisomerisation in a hydroisomerisation reactor in the <t 5 presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, © & e) introducing at least a portion of the hydroisomerisation effluent into a second separation

N 30 stage, and recovering from the second separation stage at least one or more aviation fuel range fraction and/or diesel fuel range fraction.

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 middle distillates having sustainable i.e. renewable and/or circular content, especially in aviation fuel boiling range. Incorporation of renewable and/or circular content in a hydrotreatment feed may be expected to increase n-paraffin content of at least some of the produced fractions, particularly of produced middle distillates, and hence to deteriorate their cold properties. However, with the help of the present process such deterioration may be controlled, or cold properties of the produced middle distillates having renewable and/or circular content may even be improved. Surprisingly the inventors also found that with the present process a middle distillate fraction boiling within diesel fuel boiling range and exhibiting improved response to conventional cold flow additive(s) is obtainable.

The above-mentioned advantages may be attained with reduced costs, especially when utilising existing assets of a petroleum refinery. While typical petroleum refineries have limited hydroisomerisation capacity, generally only a small fraction of refinery's hydrotreatment and (hydro)cracking capacity, the present process is well suited for running in conventional or existing petroleum refinery units, because only a selected middle distillate fraction of the hydrotreatment effluent is subjected to hydroisomerisation. By carefully selecting the middle distillate fraction to be isomerised and/or the fractions to be recovered from the process, for example in view of the properties of the hydrotreatment effluent and/or = market demand of the fractions obtainable by the present process, it is possible to further

N optimise the overall value of the product slate.

N

ES Hence, in certain preferred embodiments, the hydroisomerisation feed comprises at least a

I portion of the second middle distillate fraction, at least an aviation fuel range fraction is > 30 recovered from the second separation stage, and the aviation fuel range fraction and at = least a portion of the first middle distillate fraction are introduced into an aviation fuel range 2 pool; or the hydroisomerisation feed comprises at least a portion of the first middle distillate & fraction, at least an aviation fuel range fraction is recovered from the second separation stage, and the aviation fuel range fraction is introduced into an aviation fuel range pool.

In certain preferred embodiments, at least a portion of the second middle distillate fraction is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive, and preferably the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, at least a diesel fuel range fraction is recovered from the second separation stage and at least a portion thereof is introduced into a diesel fuel range pool, preferably into a cold climate diesel fuel range pool. Additionally or alternatively, in certain preferred embodiments the second middle distillate fraction has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 160°C to 380°C, preferably within a range from 170°C to 360°C, and a difference between T90 and T20 temperatures (EN ISO 3405-2019) atleast 68°C, preferably at least 70°C, and optionally a difference between FBP and T90 temperatures (EN ISO 3405-2019) at least 15°C, preferably at least 16°C.

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.

BRIEF DESCRIPTION OF THE FIGURES

Some example embodiments will be described with reference to the accompanying figures, in which:

Fig. 1a schematically shows a process according to an example embodiment of the present process, wherein a hydroisomerisation feed comprising at least a portion of a second middle distillate fraction is subjected to hydroisomerisation.

Fig. 1b schematically shows a process according to an example embodiment of the present

O

N process, wherein a hydroisomerisation feed comprising at least a portion of the first middle

N

J 25 distillate fraction is subjected to hydroisomerisation.

ES Fig. 2 illustrates how by carefully selecting the middle distillate fraction to be recovered from - the first separation stage for feeding to the hydroisomerisation, the value of the remaining a > middle distillate fraction(s) recovered from the first separation stage may be increased, here <t 5 in terms of enhanced quality due to improved cloud point. © & 30 Fig. 3 shows an excellent response in terms of improved cold filter plugging point to a

N conventional cold flow additive, exhibited by a second middle distillate fraction obtained by the present process.

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. 5 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.

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.

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

N diesel fuel range fraction or pool (or fuel) reference is herein made to a diesel fuel range

N fraction or pool (or fuel) meeting one or more of the cold filter plugging point requirements

E (CFPP) laid down in EN 590:2022 Table 2, and by cold climate diesel fuel range fraction or <t pool (or fuel) reference is herein made to a diesel fuel range fraction or pool (or fuel) meeting x 30 one or more of the CFPP requirements and/or cloud point (CP) requirements laid down in

S 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.

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.

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 @ 25 fractions recovered from a separation stage may boil, i.e. have IBP and FBP, within partly < overlapping ranges. Hence in the context of the present disclosure, for example expression

N “the first middle distillate fraction is a lower boiling middle distillate fraction and the second

ES middle distillate fraction is a higher boiling middle distillate fraction” generally means that

I the T50 temperature (EN ISO 3405-2019) of the first middle distillate fraction is lower than > 30 the T50 temperature of the second middle distillate fraction. More specifically it may mean = that the T60 temperature (EN ISO 3405-2019) of the first middle distillate fraction is lower 2 than the T40 temperature (EN ISO 3405-2019) of the second middle distillate fraction. & Preferably the T70 temperature (EN ISO 3405-2019) of the first middle distillate fraction is lower than the T30 temperature (EN ISO 3405-2019) of the second middle distillate fraction.

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.

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.

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.

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. & As used herein, cyclic hydrocarbons refer to all hydrocarbons containing cyclic structure(s), including cyclic olefins, naphthenes, and aromatics. Naphthenes refer herein to

N cycloalkanes i.e. saturated hydrocarbons containing at least one cyclic structure, with or

N without side chains. As naphthenes are saturated compounds, they are compounds without

E aromatic ring structure(s) present. Aromatics refer herein to hydrocarbons containing at <t least one aromatic ring structure, i.e. cyclic structure having delocalized, alternating tr bonds 3 30 all the way around said cyclic structure.

S

N 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 guantitation for individual compounds of this method is 0.1 wt.-%.

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,

N 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

N to carbon atoms of fossil origin. Therefore, it is possible to distinguish between carbon

E 30 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 3 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.

N 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, 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).

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.

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. & By hydrotreatment, sometimes also referred to as hydroprocessing, is meant herein a catalytic process of treating organic material by means of molecular hydrogen. The

N hydrotreatment reactions may include removal of oxygen from oxygenated hydrocarbons

N as water i.e. hydrodeoxygenation (HDO), sulphur from organic sulphur compounds as

E dihydrogen sulphide (H2S), i.e. hydrodesulphurisation, (HDS), nitrogen from organic <t nitrogen compounds as ammonia (NH3), i.e. hydrodenitrogenation (HDN), halogens, for 3 30 example chlorine from organic chloride compounds as hydrochloric acid (HCI), i.e. & hydrodechlorination (HDCI), and/or metals by hydrodemetallization; and/or hydrogenation

N 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.

As used herein, wherever the reaction steps are defined to take place in “reactors”, such as the hydrotreatment reactor and hydroisomerisation 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.

The present disclosure provides a process for producing hydrocarbon fractions, the process comprising: a) providing 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 first separation stage,

O and recovering from the first separation stage at least a naphtha fraction, a first middle

S 25 — distillate fraction, a second middle distillate fraction, and a first separation stage bottom,

N wherein the first middle distillate fraction is a lower boiling middle distillate fraction and the

ES second middle distillate fraction is a higher boiling middle distillate fraction,

E d) subjecting a hydroisomerisation feed comprising at least a portion of the first or the < second middle distillate fraction to hydroisomerisation in a hydroisomerisation reactor in the 3 30 presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent,

S e) introducing at least a portion of the hydroisomerisation effluent into a second separation stage, and recovering from the second separation stage at least one or more aviation fuel range fraction and/or diesel fuel range fraction.

The present process provides hydrocarbon fractions having renewable and/or circular content with improved overall economy of the process and with higher overall value of the product slate. At the same time GHG emissions and dependence from the diminishing petroleum sources is reduced. The advantages are based on a finding that when co- processing renewable and/or circular feed(s) with petroleum feed(s), the renewable and/or circular content may be enriched in the middle distillates boiling range, so that the middle distillates may have even much higher sustainable content compared to the hydrotreatment feed, as shown in the Experimental section. At the same time the yield of the middle distillates may be increased, compared to hydrotreating a petroleum feed alone, especially — in aviation fuel boiling range. Incorporation of renewable and/or circular content in the hydrotreatment feed is foreseen to increase n-paraffin content in the product fractions as e.g. typical fatty materials and liguefied waste plastics are good sources of paraffins whereof well over 50 wt.-% may be n-paraffins. Increase in n-paraffin content is generally expected to deteriorate cold properties. However, the present inventors have found that by subjecting to hydroisomerisation only a portion of the middle distillates recovered from the hydrotreatment effluent, both the cold properties of the portion subjected to hydroisomerisation and of the remaining portion of the middle distillates may be improved, as illustrated in Figure 2. Hence, the cold property reguirements, e.g. when targeting to meet cold property specifications laid down in fuel standards, pose less limitations to how much sustainable content may be fed to process. Whether subjecting the first or the second middle distillate fraction to hydroisomerisation, the total yield of hydrocarbons usable even in aviation fuels increases, compared to no isomerisation at all. Good cold properties are reguired particularly for middle distillate fractions to be used in aviation fuels. These are contributed both by the length (shortness) and the isomerisation degree of the paraffins present in the fraction. The yield increase of aviation fuel eligible fraction(s) obtainable by the present process becomes evident from Figures 1a and 1b (showing example & embodiments of the present process). The advantages are not limited to aviation fuel eligible fraction(s). The present process also enables even simultaneous production of i temperate climate diesel fuel components and cold climate diesel fuel components.

N

E 30 Surprisingly the inventors also found that a middle distillate fraction boiling within diesel fuel < boiling range, as recovered from the hydrotreatment effluent, exhibited improved response 3 to conventional cold flow additive(s). Typically cloud point and CFPP of diesel range & fractions having sustainable content are approximately the same, and such fractions do not

N respond well even to elevated cold flow additive dosages. As e.g. EN590-2022 requires diesel fuels to have much better CFPP than CP, one way of meeting the stricter CFPP requirement has been to recover diesel range fractions e.g. as lighter cuts, which however leads to over-quality in terms of CP. Moreover, even if using this approach, higher cold flow additive dosages may have been required to eventually reach the targeted CFPP.

The above-mentioned advantages may be attained with reduced investment costs, especially when utilising existing assets of a petroleum refinery, but also when investing in a new unit, as the isomerisation capacity required in the present process is far less than e.g. in a conventional HVO (hydrotreatment of vegetable oils) process, where essentially whole liquid hydrotreatment effluent is typically subjected to hydroisomerisation. Smaller hydroisomerisation unit involves also lower operating costs. By carefully selecting the fraction to be isomerised, for example in view of the properties of the hydrotreatment effluent and/or market demand of the fractions obtainable by the present process, it is possible to further optimise the overall value of the product slate.

In certain preferred embodiments, the first middle distillate fraction has a boiling point range within a range from 100°C to 330°C and the second middle distillate fraction has a boiling — point range within a range from 130°C to 400°C (EN ISO 3402-2019), preferably the first middle distillate fraction has a boiling point range within a range from 120°C to 310°C and the second middle distillate fraction has a boiling point range within a range from 150°C to 380°C (EN ISO 3402-2019), more preferably the first middle distillate fraction has a boiling point range within a range from 130°C to 310°C and the second middle distillate fraction has a boiling point range within a range from 160°C to 370°C (EN ISO 3402-2019). In these embodiments the yield and/or quality of the diesel fuel eligible fraction(s) and/or the aviation fuel eligible fraction(s) may be further improved.

In certain preferred embodiments, the first separation stage bottom has an initial boiling e point of at least 300°C (EN ISO 3405-2019), preferably at least 320°C, more preferably at

S 25 least 340*C; or the first separation stage bottom has an initial boiling point within a range

A from 300°C to 420°C (EN ISO 3405-2019), preferably within a range from 320°C to 410°C, n more preferably within a range from 340°C to 400°C. These embodiments allow recovery

N of the first and the second middle distillates with the desired boiling ranges, and provide a

E bottom fraction that has utility as a feed for down-stream processing, and also as a residual = 30 — marine fuel component. 3

N In conventional HVO processes involving both hydrotreatment of a fatty feedstock and

N hydroisomerisation of the hydrotreatment effluent, the boiling range of the hydrotreatment effluent is typically not significantly controlled before isomerisation, other than e.g. by degassing and/or stabilisation. On the contrary, in the present process a middle distillate fraction having relatively uniform composition in terms of boiling points is preferred as a hydroisomerisation feed component to facilitate optimisation of the hydroisomerisation conditions for the majority of the feed molecules. In this way formation of desired products including isoparaffins, and especially multiple-branched isoparaffins, may be enhanced and formation of less desired products or side products may be suppressed. Hence, in certain preferred embodiments, the first or the second middle distillate fraction incorporated in the hydroisomerisation feed has a difference between T95 and T5 temperatures (EN ISO 3405- 2019) at most 150°C, preferably at most 120°C, more preferably at most 100°C; or a — difference between T95 and T5 temperatures (EN ISO 3405-2019) within a range from 10°C to 150°C, preferably from 15°C to 120°C, more preferably from 20°C to 100°C. In certain further preferred embodiments, the difference between T95 and T5 temperatures (EN ISO 3405-2019) of the first or the second middle distillate fraction incorporated in the hydroisomerisation feed is lower than the difference between T95 and T5 temperatures (EN

ISO 3405-2019) of the first or the second middle distillate fraction not incorporated in the hydroisomerisation feed.

In certain particularly preferred embodiments: the hydroisomerisation feed comprises at least a portion of the second middle distillate fraction, at least an aviation fuel range fraction is recovered from the second separation stage, and the aviation fuel range fraction and at least a portion of the first middle distillate fraction are introduced into an aviation fuel range pool.

In certain other particularly preferred embodiments: the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, at least an aviation fuel range fraction is recovered from the second separation stage, and

S 25 introduced into an aviation fuel range pool.

N

Ni In certain other particularly preferred embodiments:

N the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction,

T at least a diesel fuel range fraction is recovered from the second separation stage and at x least a portion thereof is introduced into a cold climate diesel fuel range pool, and at least

S 30 — aportion of the second middle distillate fraction is introduced into a temperate climate diesel

O fuel range pool, optionally at least with a cold flow additive.

In certain preferred embodiments:

the hydroisomerisation feed comprises at least a portion of the second middle distillate fraction, at least a diesel fuel range fraction is recovered from the second separation stage and at least a portion thereof is introduced into a cold climate diesel fuel range pool and/or into a temperate climate diesel fuel range pool, and at least a portion of the first middle distillate fraction is introduced into the temperate climate diesel fuel range pool and/or into the cold climate diesel fuel range pool.

In these embodiments the yield and/or quality of the diesel fuel eligible fraction(s) and/or the aviation fuel eligible fraction(s) may be further optimised.

In certain preferred embodiments, step c) further comprises recovering from the first separation stage a further middle distillate fraction. In certain further preferred embodiments, the further middle distillate fraction has a boiling point range within a range from 100°C to 300°C, the first middle distillate fraction has a boiling point range within a range from 120°C to 330°C, and the second middle distillate fraction has a boiling point range within a range from 150°C to 400°C (EN ISO 3405-2019); and optionally at least a — portion of the further middle distillate fraction is introduced into an aviation fuel range pool and/or into a cold climate diesel fuel range pool. In these embodiments the yield and/or guality of the diesel fuel eligible fraction(s) and/or the aviation fuel eligible fraction(s) may be further improved.

In certain preferred embodiments: — at least a portion of the second middle distillate fraction is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive; and — preferably the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, at least a diesel fuel range fraction is recovered from the second 2 separation stage and at least a portion thereof is introduced into a cold climate diesel fuel

S 25 range pool.

N n These embodiments facilitate simultaneous production of components usable for at least

N two different diesel fuel grades. [an a > In certain further preferred embodiments, the second middle distillate fraction has T5 and

S T95 temperatures (EN ISO 3405-2019) within a range from 160°C to 380°C, preferably

N 30 within a range from 170°C to 360°C, and a T90-T20 distillation width i.e. a difference

N between T90 and T20 temperatures (EN ISO 3405-2019) at least 68”C, preferably at least 70°C, and optionally a distillation tail i.e. a difference between FBP and T90 temperatures

(EN ISO 3405-2019) at least 15°C, preferably at least 16°C. In these embodiments the response of the second middle distillate fraction to conventional cold flow additive(s) may be further enhanced, allowing reduced dosages of cold flow additive(s) and/or reducing the need to produce diesel fuel eligible fractions of over-quality in terms of cloud point.

In certain particularly preferred embodiments: — the first middle distillate fraction has a narrower boiling range, expressed as a difference between T95 and T5 temperatures (EN ISO 3405-2019) of said fraction, compared to the second middle distillate fraction, — the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, and — at least a portion of the second middle distillate fraction is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive.

In these embodiments the hydroisomerisation conditions for the majority of the hydroisomerisation feed molecules may be further optimised, hence achieving higher isomerisation degree. Also the response of the second middle distillate fraction to conventional cold flow additive(s) may be further enhanced as the wider boiling point range of the second middle distillate fraction facilitates greater difference between T90 and T20 temperatures (EN ISO 3405-2019) and a wider distillation tail, thereby allowing reduced dosages of cold flow additive(s) and/or reducing the need to produce diesel fuel eligible fractions of over-quality in terms of cloud point.

In certain embodiments aviation fuel additive(s) such as antioxidant(s), electrical conductivity additive(s), stabilizer(s), detergent(s), corrosion inhibitor(s), friction modifier(s), e metal deactivator(s), lubricating additive(s), antifoaming agent(s), and/or fuel dye(s) may be

S introduced into the aviation fuel range pool. In certain embodiments also other diesel fuel

N 25 — additive(s) in addition to the cold flow additive(s) may be introduced into the diesel fuel n range pool(s) including e.g. antioxidant(s), stabilizer(s), detergent(s), corrosion inhibitor(s), : friction modifier(s), metal deactivator(s), lubricating additive(s), antifoaming agent(s), and/or a fuel dye(s).

J

S The hydrotreatment is conducted in the presence of added hydrogen. The hydrotreatment

O 30 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 0.1to 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 8 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 VIB 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,

N more preferably gamma-alumina, optionally additized with minor amounts of silica or = phosphorous. These hydrotreatment catalysts are efficient, readily available, commonly

N used e.g. for HDS of petroleum feeds and are usable also for HDO of e.g. fatty feeds, and

E 30 tolerate typical impurities of the hydrotreatment feed used in the present process well. < 3 Also catalyst(s) containing acidic porous material(s), especially zeolite(s) and/or zeolite-

Q type material(s), having suitable shape-selective framework type, and optionally also metal

N 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 feed is subjected to hydrotreatment inthe hydrotreatment reactor in the presence of the hydrotreatment catalyst and a dewaxing catalyst to obtain the hydrotreatment effluent.

The first separation stage of the present process may utilise any conventional separation and/or fractionation technology. The first 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 in the hydrotreatment effluent 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, a first middle distillate fraction, a second middle distillate fraction, optional further middle distillate fraction(s), 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).

As mentioned, the hydrotreatment and hydroisomerisation effluents, and also effluents from optional pre-hydrotreatment and/or hydroconversion as described in the following may be subjected to gas-liquid separation. The gas-liquid separation of any of said effluents may @ 25 be conducted for example as an integral step within the respective reactor, or subsequently < e.g. using one or more of high pressure-high temperature, high pressure-medium

N temperature or similar separator(s). Typically, the gas-liguid separation is conducted at a

ES temperature within a range from 0 °C to 500 °C, such as from 15°C to 300°C, or from 15 °C

I to 150 °C, preferably from 15 °C to 65 °C, such as from 20 °C to 60 °C, and preferably at > 30 essentially same pressure as that of the reactor wherefrom the effluent originates. Typically, 3 the pressure during the gas-liquid separation(s) may be within a range from 0.1 MPa to 20

Q MPa, preferably from 1 MPa to 18 MPa, or from 3 MPa to 15 MPa. The gas-liquid separation

N allows to recover compounds that are gaseous under the separation conditions (herein referred to as a gaseous stream) from the respective reactor effluent.

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, light hydrocarbons, carbon monoxide, carbon dioxide and/or water. The presence and/or content of said compounds may vary. For example carbon monoxide, carbon dioxide and/or water are more abundant in a gaseous stream separated from the effluent of a reactor whereto the renewable and/or circular content is fed, and generally a gaseous stream separated from the effluent from hydroisomerisation contains predominantly residual hydrogen and some light hydrocarbons. 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 first and/or second 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 hydrotreatment in step b), to the hydroisomerisation in step d), to the optional hydroconversion in step f), and/or to the optional pre-hydrotreatment. Utilising such recycle hydrogen stream and/or make-up hydrogen stream in the present process enhances economy thereof. = The present process also involves a hydroisomerisation step, converting the selected

N middle distillate to have higher isomerisation degree, thereby improving its cold properties. = The hydroisomerisation is conducted in the presence of added hydrogen. The

N hydroisomerisation may be conducted e.g. using any hydroisomerisation reactor(s),

E 30 conditions and catalyst(s) known by a skilled person and/or conventionally used e.g. in < petroleum refineries or in HVO plants. > 2 The hydroisomerisation in the hydroisomerisation reactor may for example be conducted at & a temperature within a range from 200 °C to 500 °C, preferably from 230 °C to 450 °C, a pressure within a range from 1 MPa to 10 MPa, preferably from 2 MPa to 8 MPa or from 3

MPato 10 MPa, a H2 partial pressure at the inlet of the hydroisomerisation reactor within a range from 1 MPa to 10 MPa, preferably from 2 MPa to 8 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8, more preferably from 0.4 to 6 kg hydroisomerisation feed per kg catalyst per hour, and a H2 to hydroisomerisation feed ratio within a range from 10 to 2000, preferably from 50 to 1000 normal liters H2 per liter — hydroisomerisation feed, in the presence of a hydroisomerisation catalyst.

The hydroisomerisation catalyst may be any conventionally used hydroisomerisation catalyst or combination thereof, no special catalysts are needed. For example, one of the hydroisomerisation catalysts loaded in the hydroisomerisation reactor may be highly selective for isomerisation reactions and another hydroisomerisation catalyst may have selectivity also towards ring-opening reactions. Typically the hydroisomerisation catalyst comprises at least one or more Group VIII metal, and at least one or more acidic porous material such as zeolites and/or zeolite-type materials. Noble metals are preferred as they may provide higher selectivity towards isomerisation reactions under the conditions in the hydroisomerisation reactor, and are highly active at lower operating temperatures, compared to catalysts comprising only non-noble metals. High activity at lower temperatures provides a wider temperature range within which temperature may be adjusted, typically increased, during operation. Gradual catalyst deactivation occurring when the process is operated for longer time periods may be compensated to a certain extent by increasing temperature in the reactor.

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 FI1100248B, EP1741768A1,

EP1741768A1, EP2155838B1, FI129220B1, EP1396531A2, or EP0985010A1. Hence, in @ 25 certain embodiments the hydroisomerisation catalyst is a bifunctional hydroisomerisation < catalyst, preferably a non-sulphided bifunctional hydroisomerisation catalyst, comprising at

N least one or more metals selected from Group VIII of the Periodic Table, preferably from Ni,

ES Pt and/or Pd; and at least one or more acidic porous materials selected from zeolites and/or

I zeolite-type materials, wherein preferably at least one or more of the zeolites and/or zeolite- > 30 type materials has a framework type selected from AEL, ATO, AFO, EUO, FER, MTT, = and/or TON, preferably at least one or more acidic porous materials selected from SAPO- 2 11, SAPO-31, SAPO-41, ZSM-22, ZSM-23, ZSM-48, EU-1, and/or ferrierite; and optionally & at least one or more of alumina, silica, and/or amorphous silica-alumina. This catalyst selection has been found to provide high isomerisation selectivity further enhancing the yield of isoparaffins, particularly multiple-branched isoparaffins, which have excellent cold properties such as very low freezing point and/or cloud point. The mentioned SAPOs and zeolites are commercially available with acidity and porosity characteristics that allow isomerisation, including multiple-branching, of n-paraffins, even of long-chained n-paraffins, such as C16+ paraffins typically present in renewable and/or circular feeds.

As the hydrotreatment in step b) cleaves efficiently S and N bound in the feed molecules forming H2S and NH3 gases, and only the selected middle distillate continues to the hydroisomerisation, rapid deactivation of the noble metal hydroisomerisation catalyst is not a concern.

The hydroisomerisation step converts at least a certain amount of n-paraffins in the — hydroisomerisation feed to i-paraffins, and preferably also causes ring-opening of cyclic hydrocarbons that may also be present in the hydroisomerisation feed. Depending on the targeted isomerization degree, that may be controlled by adjusting severity of the hydroisomerization, more of the n-paraffins can be converted to i-paraffins, and mono- branched i-paraffins to multibranched i-paraffins, such as di-branched and/or tri-branched — i-paraffins, even i-paraffins comprising more than three branches. Also some cracking reactions may occur during the hydroisomerisation. The severity of the hydroisomerisation may be increased e.g. by at least one or more of: decreasing WHSV, increasing temperature, and/or increasing pressure. When using fresh hydroisomerisation catalyst, high severity hydroisomerisation conditions may be reached at lower temperature and/or pressure, and/or using higher WHSV, than towards the end of the hydroisomerisation catalyst lifetime. The more homogeneous the hydroisomerisation feed, especially in terms of boiling points of the feed molecules, the easier it may be to apply essentially egual severity conditions for the majority of the feed molecules. n There may be further steps included either combined with the hydroisomerization step, or

S 25 after recovery of the aviation and/or diesel fuel range fraction. These may include e.g. a hydropolishing, dearomatizing, stabilisation, just to name a few. Typically, such additional i process steps aim at better control of desired properties of the recovered fractions.

N

E The second separation stage of the present process may comprise any conventionally used <t fractionation technology, and may be arranged similarly as disclosed in connection with the 3 30 first separation stage. However, since only a portion of the middle distillates recovered from & the hydrotreatment effluent are fed to the hydroisomerisation, the second separation stage

N may be much smaller, hence involving lower investment and operating costs. For the same reason, and especially when the first or the second middle distillate fraction incorporated in the hydroisomerisation feed has relatively narrow boiling range, mere gas-liquid separation and optionally stabilisation may suffice for the hydroisomerisation effluent, thereby further reducing the investment and operating costs of the second separation stage, and maximising yield of the recovered at least one or more aviation fuel range fraction and/or diesel fuel range fraction.

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 for an aviation fuel. A diesel fuel range 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.

In the present process, at least one or more aviation fuel range fraction and/or diesel fuel range fraction is/are recovered from the second separation stage, depending e.g. on the — hydroisomerisation operating conditions chosen, composition of the hydroisomerisation feed, and/or market demand at a given time. The high isomerisation degree of the recovered aviation fuel range fraction and/or diesel fuel range fraction 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.

Since the present process allows optimising the hydroisomerisation conditions and thereby maximisation of isomerisation degree, the obtained at least one or more aviation fuel range e fraction and/or diesel fuel range fraction may have very high isoparaffin content, generally

S 25 atleast 85 wt.-%, preferably at least 90 wt.-%, more preferably at least 95 wt.-%, based on a the total weight of paraffins in the fraction, and a high multiple-branched isoparaffin content, i generally at least 50 wt.-%, preferably at least 55 wt.-%, more preferably at least 60 wt.-%,

N based on the total weight of paraffins in the fraction. High isomerisation degree contributes

E to good cold properties such as lower freezing point, lower kinematic viscosity at -20 *C, = 30 and lower cloud point, without a need to reduce the final boiling point of the fraction. >

N The at least one or more aviation fuel range fraction and/or diesel fuel range fraction

N recovered from the second separation stage may for example include an aviation fuel range fraction having a boiling point range within a range from about 120 °C to about 310 °C,

preferably from about 130 °C to about 300 °C (EN ISO 3405-2019), and/or a diesel fuel range fraction boiling within a range from about 130 °C to about 380 °C, preferably from about 160 °C to about 370 °C (EN ISO 3405-2019).

In certain preferred embodiments of the present process, at least one aviation fuel range fraction is recovered from the second separation stage having at least one or more of the following properties: a density at 15°C within a range from 775 to 840 kg/m3, final boiling point at most 300 °C (EN ISO 3405-2019), a T10 temperature at most 205°C (EN ISO 3405- 2019), a kinematic viscosity at -20 °C at most 8.0 mm2/s (EN ISO 3104-2020), a flash point at least 38 °C (IP 170-2013, Abel closed-cup method), and/or a freezing point at most -40°C — (IP 529-2016). In these embodiments the recovered aviation fuel range fraction is of high quality, and may be introduced into aviation fuel range pools (or fuels) in elevated amounts, or even without restrictions.

In certain preferred embodiments of the present process, at least one diesel fuel range fraction is recovered from the second separation stage having at least one or more of the — following properties: a density at 15 °C within a range from 800 to 845 kg/m3 (EN ISO 12185-1996), a T10 temperature at least 180 °C (EN ISO 3405-2019), a T95 temperature at most 340 °C (EN ISO 3405-2019), cetane at least 51.0 (EN ISO 15195-2014), a kinematic viscosity at 40 °C within a range from 1.2 to 4.0 mm2/s (EN ISO 3104-2020), and/or a cloud point at most -10 °C (EN ISO 3015-2019). In these embodiments the recovered diesel fuel range fraction is of high quality, and may be introduced into cold climate diesel fuel range pools (or fuels) in elevated amounts, or even without restrictions.

Generally, when the hydrotreatment feed has renewable content, i.e. contains biogenic carbon, the first middle distillate fraction and/or the second middle distillate fraction e recovered from the first separation stage, and/or at least one or more aviation fuel range

S 25 fraction and/or diesel fuel range fraction recovered from the second separation stage may a have a biogenic carbon content (EN 16640:2017) that is higher than the biogenic carbon i content of the hydrotreatment feed. The biogenic carbon content in the recovered fraction(s)

N is influenced by the biogenic carbon content in the hydrotreatment feed, by the selection of

E the cut-point values in the first and/or second separation stage, and by the selection of cut-

J 30 point value(s) in an optional pre-hydrotreatment fractionation described in the following.

S Similar considerations apply to the circular carbon content, for which however no analysis

O method exists.

Hence, in certain preferred embodiments, the hydrotreatment feed has a biogenic carbon content within a range from 5 to 95 wt.-%, based on the total weight of carbon (TC) in the hydrotreatment feed (EN 16640:2017), preferably within a range from 5 to 90 wt.-%, more preferably from 10 to 85 wt.-%, even more preferably from 15 to 80 wt.-%; and the first middle distillate fraction and/or the second middle distillate fraction recovered from the first separation stage, and/or at least one or more aviation fuel range fraction and/or diesel fuel range fraction recovered from the second separation stage has/have a biogenic carbon content of at least 20 wt.-%, based on the total weight of carbon (TC) in the hydrotreatment feed (EN 16640:2017), preferably at least 40 wt.-%, more preferably at least 50 wt.-%, even — more preferably at least 60 wt.-%.

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 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 first separation stage bottom. Hence, in certain preferred embodiments, a residual marine fuel component is recovered from the first separation stage bottom, preferably by splitting a portion from the first separation stage bottom. Surprisingly it was found that a marine fuel range component recovered from the first separation stage bottom, especially from a first separation stage bottom having an initial boiling point of at least 300°C (EN ISO 3405-2019), preferably at least 320°C, more preferably at least 340°C, such as within a range from 300°C to 420°C (EN ISO 3405-2019), from 320°C to 410°C, or from 340°C to 400°C, 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. This could be achieved simply by splitting a portion from the first separation stage bottom. Hence, = recovery of a residual marine fuel component therefrom further improves the overall value

N of the product slate of the present process. In certain preferred embodiments, wherein the = residual marine fuel component is recovered from the first separation stage bottom at a rate

N ranging from 3 wt.-% to 30 wt.-%, preferably from 3 wt.-% to 20 wt.-%, more preferably from

E 30 5wt-%to 15 wt.-%, based on the total weight of the separation stage bottom. The residual < marine fuel range component having renewable and/or circular content, as obtainable by 3 the present process, helps to reduce GHG emissions in shipping and meet the target of & 50% GHG emission reduction by 2050.

N

In certain preferred embodiments, the process further comprises f) subjecting a heavy — hydroconversion feed comprising at least a portion of the first separation stage bottom,

which preferably has an initial boiling as specified in the foregoing, and optionally at least a portion of the second middle distillate, to hydroconversion in a hydroconversion reactor in the presence of hydrocracking and/or hydroisomerisation catalyst(s) to obtain a hydroconversion effluent, and optionally co-feeding at least a portion of the hydroconversion effluent with the hydrotreatment effluent to the first separation stage. By hydrocracking the heavy molecules recovered in the first fractionation bottom, the yield of lighter boiling fractions, especially of the first and the second middle distillate, may be further increased.

Benefits of using isomerisation include further enhancement of the cold properties. Hence, these embodiments may further improve the overall value of the product slate of the present — process.

The optional hydroconversion is conducted in the presence of added hydrogen. When the hydroconversion in the hydroconversion reactor is conducted in the presence of a hydrocracking catalyst, preferably the hydrocracking conditions and catalyst(s) as specified below are used. When the hydroconversion in the hydroconversion reactor is conducted in — the presence of a hydroisomerisation catalyst, preferably the hydroisomerisation conditions and catalysts as specified in the foregoing are used. When both hydrocracking and hydroisomerisation catalysts are utilised in the hydroconversion, preferably hydroconversion conditions meeting both the hydrocracking conditions as specified below and the hydroisomerisation conditions as specified in the foregoing are utilised.

The hydrocracking may be conducted 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 @ 25 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

N 0.1 to 10, preferably from 0.2 to 8 kg hydrocracking feed per kg catalyst per hour, and a H2

ES to hydrocracking feed ratio within a range from 50 to 2000, preferably from 500 to 1500

I normal liters H2 per liter hydrocracking feed, in the presence of a hydrocracking catalyst. > 30 — Within these conditions the efficiency of the hydrocracking step in terms of selectivity and/or 3 activity regarding hydrocracking reactions may be further enhanced, hydrocracking catalyst

Q deactivation controlled, undesired side reactions suppressed and desired conversion level

N 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 WO02011007046. 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 zeolite- — type materials has a framework type selected from MFI, BEA, FAU, 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 and & optionally at least a portion of the second middle distillate, would continue to the hydrocracking, rapid deactivation of the noble metal hydrocracking catalyst is not a concern.

N when the recovery rate of the optionally recovered residual marine fuel component is fixed,

E 30 i.e. maintained approximately constant, the hydrocracking conversion may vary and be < increased e.g. by increasing the hydrocracking temperature and/or decreasing WHSV. 3 Alternatively, the recovery rate of the optionally recovered residual marine fuel component & may be varied preferably within the ranges specified in the foregoing, while targeting fixed

N hydrocracking conversion. The inventors found that by separating, at least periodically, a portion of the first 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 hydroconversion unit and the first separation stage, and contributing beneficially to the quality and distribution of the fractions recovered from the present process.

The advantages of the present process may be attained with reduced investment 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, although an optionally used pre-hydrotreatment reactor may need to be made of higher metallurgy grade than conventional petroleum refinery units so as to withstand renewable and/or circular feeds of even very low quality. 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 first separation stage, the hydroisomerisation reactor, the second separation stage, and/or the hydroconversion reactor are as originally configured to treat a petroleum feed. While typical petroleum refineries have limited hydroisomerisation capacity, the — present process is well suited for running in existing petroleum refinery units, because only a given fraction of the hydrotreatment effluent is required to be hydroisomerised. Using existing petroleum refinery units of a petroleum refinery provides also enhanced flexibility, 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.

In certain embodiments, at least a portion of the naphtha fraction and/or of a further middle distillate fraction optionally recovered from the first separation stage is/are introduced into a gasoline fuel range pool, or used as a steam cracker feed; and/or wherein fuel gases @ 25 and/or a light naphtha fraction is/are further recovered from the first and/or the second < separation stage, and at least a portion thereof is fed to a hydrogen production unit,

N preferably to a steam reforming unit, to obtain a syngas, followed by recovering a make-up

ES hydrogen stream from the syngas. While majority of the renewable and/or circular content

I resides in the middle distillate range, depending e.g. on the boiling point range of the > 30 molecules providing the renewable and/or circular content, and on the IBP of the lowest = boiling middle distillate fraction recovered from the first separation stage, some of the 2 renewable and/or circular content may also end-up in the fuel gases and naphtha fraction. & The elevated n-paraffin content in the naphtha fraction, originating particularly from the renewable and/or circular content, is desired for certain down-stream processes such as isomerisation and alkylation, and also in petchem field such as for steam cracker feeds. For octane rating, which is important for gasoline fuel purposes, elevated n-paraffin content could be troublesome. However, the petroleum feed derived content comprising e.g. cyclic hydrocarbons contributes beneficially to the octane rating of the naphtha fraction. This is particularly beneficial when at least one of the recovered naphtha fractions is to be introduced into a gasoline fuel range pool, or into a catalytic naphtha reformer to produce a reformate gasoline fraction. Furthermore, when at least one of the recovered naphtha fractions is a light naphtha fraction, such light naphtha fraction may be utilised for make-up hydrogen production. Hence, these embodiments may further improve the overall value of the product slate of the present process and/or, when an optionally produced make-up hydrogen stream is recycled to the hydrotreatment, hydroisomerisation, optional pre- hydrotreatment and/or optional hydroconversion reactors, also the process economy.

In the present process, at least a naphtha fraction, a first middle distillate fraction, a second middle distillate fraction, and a first separation stage bottom are recovered from the first separation stage. According to certain embodiments of the present process, also further naphtha fraction(s) and/or further middle distillate fraction(s) may be recovered from the first separation stage, and/or optionally from the second separation stage. At least one or more of the recovered naphtha fraction(s), first middle distillate fraction, second middle distillate fraction, optional further middle distillate fraction(s), aviation fuel range fraction, diesel fuel range fraction and/or optional residual marine fuel range component 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

N 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

N detergents, in cleaners, in plasticizing oils, in turbine oils, in hydrophobization compositions,

E 30 in agriculture, in crop protection fluids, in construction, in concrete demoulding formulations, < in electronics, in medical appliances, in compositions for car, electrical, textile, packaging, 3 paper, cosmetic and/or pharmaceutical industry, and/or in manufacture of intermediates & therefor. The elevated renewable and/or circular content, especially biogenic carbon

N content, that may be abundant particularly in the recovered middle distillate range fractions, add value in all these applications.

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 may originate 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. Typical vegetable oil(s) animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and/or liguefied 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 liguefied 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

Tr such as bagasse, vinasses, molasses and/or greenhouse wastes, energy crops like

N 30 miscanthus, switchgrass, sorghum, and/or jatropha; and/or lignocellulosic industrial waste z 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,

S restaurant wastes. The liguefied organic waste may comprise thermally such as

O hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liguefied 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.

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 pre- treatment 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 hydrotreatment or in the pre-hydroteatment, 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.

Vegetable oil(s), animal fat(s), microbial oil(s), and lignocellulose-derived biocrude(s) are essentially biogenic and may hence be preferred feeds for providing renewable content. On the other hand, typical fatty materials such as vegetable oil(s), animal fat(s), and/or @ 25 microbial oil(s), as well as liquefied organic waste tend to form paraffins upon the pre- < hydrotreatment and/or hydrotreatment, whereof well over 50 wt.-% may be n-paraffins, that

N are e.g. excellent cetane enhancers. Paraffins are also easy to isomerise compared to cyclic

ES hydrocarbons that may be abundant e.g. in lignocellulose-derived biocrude(s). Vegetable

I oil(s), animal fat(s), and/or microbial oil(s) may be regarded as further preferred feeds for > 30 providing renewable content, due to the renewable propane formed from the glycerol 3 backbone typically present in these lipidic materials. The formed propane may be separated

Q from the pre-hydrotreatment effluent and/or from the first separation stage and utilised e.g.

N 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 step a) comprises 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 a pre-hydrotreatment.

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.-%. In embodiments using a pre-hydrotreated 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). However, when the hydrotreatment feed contains non-pre-hydrotreated and hence potentially acidic renewable and/or circular feeds, the combined share of petroleum content and optional pre- hydrotreated renewable and/or circular content in the hydrotreatment feed is advantageously at least 50 wt.-% or at least 70 wt.-%, so as to mitigate the increased — corrosion risk by dilution.

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.

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- e run petroleum distillates. In this way, the overall value of a product slate of an entire

S 25 petroleum refinery may be optimised. Hence, in certain preferred embodiments, the a petroleum feed comprises at least one or more of atmospheric distillation bottom(s); vacuum i distillate(s); atmospheric and/or vacuum distillate(s) of (hydro)cracked atmospheric and/or

N vacuum distillation bottom(s); atmospheric distillation bottom(s) of (hydro)cracked

E atmospheric and/or vacuum distillation bottom(s); atmospheric and/or vacuum distillate(s)

J 30 of (hydro)cracked vacuum distillate(s); and/or atmospheric bottom(s) of (hydro)cracked

S vacuum distillate(s), of a petroleum crude oil. In embodiments where petroleum feed is co-

O fed at several locations, such as to two or more of the pre-hydrotreatment reactor, pre- hydroteratment fractionation and hydrotreatment reactor, different petroleum feed gualities may be co-fed at different locations. For example, a petroleum feed fed to the pre-

hydrotreatment reactor may contain other and even heavier materials than exemplified above, while a petroleum feed fed to the hydrotreatment reactor is preferably as exemplified above. To maximise the sustainable content in the hydrotreatment feed, at least part of the renewable and/or circular content may be introduced into the hydrotreatment reactor as pre- hydrotreated, and part as non-hydrotreated.

In certain preferred embodiments, step a) comprises: a1) combining a petroleum feed 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, and/or a2) 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-hydrotreatment in a pre-hydrotreatment reactor in the presence of a pre-hydrotreatment catalyst to obtain a pre-hydrotreatment effluent, and co-feeding a petroleum feed to the pre-hydrotreatment reactor and/or combining a petroleum feed with at least a fraction of the pre-hydrotreatment effluent, to obtain the hydrotreatment feed having petroleum content as well as renewable and/or circular content.

The embodiment according to al) is perhaps the simplest way to provide the hydrotreatment feed having petroleum content as well as renewable and/or circular content, as no pre-hydrotreatment unit is needed. The petroleum feed and the renewable and/or circular feed may be co-fed e.g. via separate inlets to same hydrotreatment catalyst bed, or in this order to catalyst beds following one after another, to form the hydrotreatment feed in-situ in the hydrotreatment reactor, so that not even a blending vessel is needed.

Alternatively, the petroleum feed and the renewable and/or circular feed may be co-fed as

O a preformed blend. Additionally, the embodiments according to a1) may help to focus the

S 25 renewable and/or circular content, and hence also the n-paraffin content, to a better defined,

N narrower boiling fraction in the hydrotreatment effluent, thereby providing even more

ES uniform or optimised middle distillate fraction for the hydroisomerisation feed. In these

I embodiments the petroleum feed may be seen as a diluent for the at least one or more of > vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and/or = 30 liquefied organic waste and thereby to control temperature increase in the hydrotreatment 2 reactor caused by the exothermic reactions. Hence, in certain embodiments according to

N a1), the total content of 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 in the hydrotreatment feed is advantageously limited to at most 90 wt.-%, preferably at most 80 wt.-%, more preferably at most 60 wt.-%, and/or at least a portion of the hydrotreatment effluent is recycled to the hydrotreatment reactor, so as to further control reactor exotherm.

Furthermore, in certain embodiments according to a1), where the renewable and/or circular feed comprises acidic components, the total content of 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 in the hydrotreatment feed is advantageously limited to at most 50 wt.-% or at most 30 wt.-%, and/or at least a portion of the hydrotreatment effluent is recycled to the hydrotreatment reactor, so as to further mitigate potentially increased corrosion risk.

In certain particularly 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 liguefied organic waste to a pre-hydrotreatment in a pre-hydrotreatment reactor in the presence of a pre-hydrotreatment catalyst to obtain a pre-hydrotreatment effluent, and combining a petroleum feed with at least a fraction of the pre-hydrotreatment effluent to obtain the hydrotreatment feed having petroleum content as well as renewable and/or circular content. In the absence of petroleum feed in the pre-hydrotreatment step, sulphur may be present only in limited amounts, e.g. only to keep the hydrotreatment catalyst sulphided, thereby favouring hydrodeoxygenation reactions over decarboxylation/ decarbonylation reactions, and also the pre-hydrotreatment conditions, including temperature and/or pressure, may be optimised for the same.

Benefits of embodiments involving pre-hydrotreatment of at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and/or liguefied organic waste, such as embodiments according to a2), include that there are virtually no restrictions how much renewable and/or circular content may be incorporated in the hydrotreatment feed in view of reactor exotherm and/or corrosion risk mitigation, as the pre- @ 25 — hydrotreatment efficiently reduces content of heteroatoms and other impurities, and hence < also acidity. In this way even highly challenging feedstocks may be introduced - as pre-

N hydrotreated - into conventional petroleum refinery units. However, the pre-hydrotreatment

ES reactor itself may need to be made of higher metallurgy grade than conventional petroleum

I refinery units. Additionally, in embodiments involving pre-hydrotreatment, the efficiency of > 30 the hydrotreatment step e.g. to reduce heteroatom content, saturate olefins and = dearomatize may remain essentially unaffected. The hydrotreatment efficiency may even 2 increase compared to an otherwise similar process but incorporating the same amount of & renewable and/or circular content in the hydrotreatment feed but as non-pre-hydrotreated.

The pre-hydrotreatment may involve some cracking of the vegetable oil(s), animal fat(s), — microbial oil(s), lignocellulose-derived biocrude(s), and/or liquefied organic waste, so that the pre-hydrotreatment effluent incorporated in the hydrotreatment feed may lead the renewable and/or circular content to be further spread over a wider boiling range in the hydrotreatment effluent. However, this may be mitigated by certain preferred embodiments, wherein the pre-hydrotreatment effluent is fed to a pre-hydrotreatment fractionation to recover at least one or more pre-hydrotreatment distillate(s), and a pre-hydrotreatment fractionation bottom, so that only a fraction of the pre-hydrotreatment effluent, preferably the pre-hydrotreatment fractionation bottom, is incorporated in the hydrotreatment feed.

These embodiments involve the additional benefit that the other fractions recovered from the pre-hydrotreatment fractionation may be directed to other value-adding uses or — processes. By suitably selecting the cut-point(s) in the pre-hydrotreatment fractionation, an optimal utilisation and value addition of the renewable and/or circular content may be achieved.

Hence, in certain preferred embodiments, step a) comprises feeding the pre-hydrotreatment effluent to a pre-hydrotreatment fractionation to recover one or more pre-hydrotreatment — distillate(s) and a pre-hydrotreatment fractionation bottom, combining a petroleum feed with the pre-hydrotreatment fractionation bottom to obtain the hydrotreatment feed; the process further comprising: h) feeding the one or more pre-hydrotreatment distillate(s) to a catalytic conversion, preferably to a catalytic conversion comprising at least hydroisomerisation, more preferably toa 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 liguefied organic waste, to obtain a catalytic conversion effluent; and i) optionally recovering from the catalytic conversion effluent at least an aviation fuel co 25 component and/or a diesel fuel component. &

NA Due to the removal of the pre-hydrotreatment fractionation bottom containing the heaviest n compounds, processing of the pre-hydrotreatment distillate(s) in subseguent catalytic

N conversions may be easier, involving reduced risk of dusting in catalyst beds and/or : pressure drop over fixed catalyst beds. Additionally the pre-hydrotreatment distillate(s) are = 30 good diluents for oxygenated hydrocarbons in hydroprocessing, and help to control the 3 hydroprocessing exotherm and/or corrosion risk. The embodiments involving

O hydroisomerisation allow recovery of a further aviation fuel component and/or a further diesel fuel component having high isomerisation degree, thereby further increasing yield of fractions/products having improved cold properties.

The optional pre-hydrotreatment is conducted in the presence of added hydrogen. The pre- 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 pre-hydrotreatment may be carried out as disclosed in the foregoing for the hydrotreatment, or at somewhat milder conditions. Hence, in certain preferred embodiments, the pre-hydrotreatment in the pre-hydrotreatment reactor may 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-hydrotreatment reactor within a range from 3 MPa to

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-hydrotreatment feed per kg catalyst per hour, and a H2 to pre-hydrotreatment feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter pre-hydrotreatment feed, in the presence of a pre- 15 — hydrotreatment catalyst. Selecting the pressure and/or the temperature within these ranges 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 pre-hydrotreatment effluent.

The pre-hydrotreatment catalyst may be as disclosed in the foregoing for the hydrotreatment catalyst. By incorporating petroleum content in the pre-hydrotreatment feed, the pre-hydrotreatment catalyst may remain sufficiently sulphided and hence sufficiently active even without separate sulphur spiking. Alternatively or additionally, the pre- hydrotreatment feed may be spiked with additional sulphur to maintain the pre- @ 25 — hydrotreatment catalyst sufficiently sulphided and active. &

A By pre-hydrotreating the renewable and/or circular feed(s), formation of carbon dioxide and n carbon monoxide in the hydrotreatment step may be minimised or even eliminated. While

N CO2 may be efficiently removed from reactor effluents gaseous phase using conventional

E purification technologies, such as sweetening removing both H2S and CO2, CO may

J 30 accumulate in the recycle hydrogen stream that may be recovered from the gaseous stream

S separated from pre-hydrotreatment effluent, thereby limiting e.g. how much of the recycle

O hydrogen stream could actually be recycled back e.g. to the present process or to refinery's other hydrotreatment, hydroisomerisation and/or hydrocracking units. By subjecting the renewable and/or circular feed(s) to pre-hydrotreatment, the conditions in the pre-

hydrotreatment 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-hydrotreatment reactor.

Using a separate pre-hydrotreatment step also allows a gaseous stream separated from the pre-hydrotreatment effluent to be specifically processed so as to mitigate issues relating to CO accumulation in a recycle hydrogen stream recovered from the gaseous stream.

The optional pre-hydrotreatment fractionation of the pre-hydrotreatment effluent may comprise any conventionally used fractionation technology and may be arranged similarly as described in the following in connection with the first separation stage. However, since — only the renewable and/or circular content to be incorporated in the hydrotreatment feed (or only part thereof) would be subjected to the pre-hydrotreatment, the pre-hydrotreatment 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-hydrotreatment effluent, thereby further reducing the investment and operating costs of the pre-hydrotreatment fractionation, and maximising yield of the renewable and/or circular molecules to be subjected to the hydrotreatment.

Schematic presentation of the process

Fig. 1a schematically shows a process according to an example embodiment. Fig. 1a also shows alternative ways of providing a hydrotreatment feed HTF having petroleum content as well as renewable and/or circular content. A sustainable feed S such as vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and/or liquefied organic waste may be introduced into a pre-hydrotreatment reactor 100, optionally together with a petroleum feed P1, and/or a petroleum feed P2 may be combined with the pre- e hydrotreatment effluent, and/or a petroleum feed P3 may be combined with a fraction

S 25 separated in a pre-hydrotreatment fractionation 110 from the pre-hydrotreatment effluent, a to provide a hydrotreatment feed HTF having petroleum content as well as renewable i and/or circular content. Alternatively or additionally, a sustainable feed S such as vegetable

N oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and/or liquefied

E organic waste may be blended with a petroleum feed P3 or they may be co-fed separately

J 30 to a hydrotreatment reactor 200, thereby providing a hydrotreatment feed HTF having

S petroleum content as well as renewable and/or circular content. In the hydrotreatment

O reactor 200 the hydrotreatment feed HTF is subjected to hydrotreatment in the presence of a hydrotreatment catalyst and optionally a dewaxing co-catalyst to obtain a hydrotreatment effluent whereof at least a portion is introduced into a first separation stage 300. From the first separation stage 300 at least a naphtha fraction 410, a first middle distillate fraction 430, a second middle distillate fraction 440, and a first separation stage bottom 420, and optionally at least one or more further middle distillate fraction 450, are recovered, wherein the first middle distillate fraction 430 is a lower boiling middle distillate fraction and the second middle distillate fraction 440 is a higher boiling middle distillate fraction. In Fig. 1a, a hydroisomerisation feed comprising at least a portion of the second middle distillate fraction 440 is subjected to hydroisomerisation in a hydroisomerisation reactor 500 in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, whereof at least a portion is introduced into a second separation stage 510. From the second separation stage 510 at least one or more aviation fuel range fraction 610 and/or diesel fuel range fraction 620 is/are recovered. At least a portion of the diesel fuel range fraction 620 may be introduced into a cold climate diesel fuel range pool and/or into a temperate climate diesel fuel range pool. In Fig. 1a it is also shown that at least a portion of the first middle distillate fraction 430 and the aviation fuel range fraction 610 may be introduced into an — aviation fuel range pool 710, optionally with aviation fuel additives 750. In Fig. 1a it is also shown that at least a portion of the second middle distillate fraction 440 may be introduced into a temperate climate diesel fuel range pool 720, optionally at least with a cold flow additive 760. Fig 1a also shows that optionally a residual marine fuel component may be recovered from the first separation stage bottom 420 by splitting a portion therefrom, that a — hydroconversion feed comprising the remaining portion of the first separation stage bottom may be subjected to hydroconversion in a hydroconversion reactor 800 in the presence of hydrocracking and/or hydroisomerisation catalyst(s) to obtain a hydroconversion effluent 810, and that at least a portion thereof may be co-fed with the hydrotreatment effluent to the first separation stage 300.

Fig. 1b schematically shows a process according to an example embodiment, similar to the = example embodiment shown in Fig. 1a, but differing therefrom e.g. in that a

N hydroisomerisation feed comprising at least a portion of the first middle distillate fraction = 430 is subjected to hydroisomerisation in a hydroisomerisation reactor 500 in the presence

N of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, whereof at least a

E 30 portion is introduced into a second separation stage 510. From the second separation stage < 510 at least one or more aviation fuel range fraction 610 and/or diesel fuel range fraction 3 620 is/are recovered. The diesel fuel range fraction 620 may be introduced into a cold & climate diesel fuel range pool. In Fig. 1b it is also shown that the aviation fuel range fraction

N 610 and at least a portion of a further middle distillate fraction 450 optionally recovered from the first separation stage 300 may be introduced into an aviation fuel range pool 710,

optionally with aviation fuel additives 750. In Fig. 1b it is also shown that at least a portion of the second middle distillate fraction 440 may be incorporated in a temperate climate diesel fuel range pool 720, optionally at least with a cold flow additive 760.

EXAMPLES

EXAMPLE 1 — Pre-hydrotreatment of three different renewable feeds and co- hydrotreatment with a petroleum feed

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-liguid separation, portion of the liguid 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 pre- hydrotreatment 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 1A and 1B.

S Table 1A. Brief description of the hydrotreatment feeds.

N | ; Hydrotreatment feed

N Nitrogen content, w-ppm (ASTM D5762-2018a) — 1720 =; 1540..1580 —-

Light gas oil" ; 20 | 20

Gas oil" ; 8 | 8

Light vacuum gas oil, lighter fraction* ; 10 | 10

Light vacuum gas oil, heavier fraction* | 11 | 11 st or S2 or S3 (see Table 1B) | 0 | 25 * distillate of hydrocracked mixture of crude oil vacuum distillate and vacuum distillation bottom as deasphalted

Table 1B. Brief description of certain hydrotreatment feed components. feed component Brief description oil (only in Pr) {paraffins, 30 wt.-% naphthenes, 50 wt.-% aromatics. i % CTO, IBP (EN ISO 3405-2019) 320*C. About 68 wt.-% paraffins, 16 wt.-% i naphthenes, 16 wt.-% aromatics.

S2 Bottom fraction of pre-hydrotreated mixture of 40 wt.-% animal fat and 60 wt.- % CTO, IBP (EN ISO 3405-2019) 320*C. About 49 wt.-% paraffins, 30 wt.-% i naphthenes, 21 wt.-% aromatics.

N i 340°C. About 32 wt.-% paraffins, 40 wt.-% naphthenes, 28 wt.-% aromatics.

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 ht.

N

= From the hydrotreatment effluent a gaseous stream containing gases and low-boiling

N 10 hydrocarbons was removed to obtain a liquid hydrocarbon stream that was distilled to obtain

E 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 3 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

N 15 — 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.

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™'. 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 Pr alone as the hydrotreatment feed are reported in Table 2.

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

Mass balance | Boiling point | 100 wt.-% | 75 wt.-% P | 75 wt.-% P + | 75 wt.-% P +| %-change range (EN Pr + 25 wt.-% | 25 wt.-% S2 | 25 wt.-% S3 | compared to

ISO 3405- S1 reference 2019)

Total < 85 *C 1.1 1.6 (reduced or hydrocarbon increased) gases, wt.-%

Gasoline 85-180 *C 15 10 11 Reduced by range, wt.-% ~40%

Middle 180-360 °C 65 65 Increased by distillates, wt.- ~9% %

Bottom 360 °C-FBP 19 20 21 19 Increased at (VGO), wt.-% (18) (17) (15) (18) most by 0 (bleed) ~10%

S Losseswt-%| - | 3 | 3 [| 3 | 3 | -

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N 15 From Table 2 it can be seen that by co-processing 25 wt.-% of the sustainable component

ES S1, S2 or S3, 5-6 wt.-% higher middle distillates yield could be obtained compared to

I 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 <t 5 40%), and the yield of separation stage bottom was same or at most 1-2 wt.-% higher (i.e.

O

Q 20 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 Example 3, some fractions in the middle distillate range had more than 2x the biogenic carbon content of the hydrotreatment feed, making their increased yield even more valuable. Also the separation stage bottom was found to have improved value, as having sustainable content and being suitable for use in marine fuels. 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.

Based on the results shown in Table 2, it seems that the distribution of the products and the sustainable content may be easily fine-tuned e.g. 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 higher-boiling middle distillates and the sustainable content therein may be increased, while by co-feeding a pre-hydrotreatment effluent just as degassed and optionally stabilised (without further fractionation), or by feeding e.g. non-pre-hydrotreated fatty feed, the yield of general range of middle distillates and the sustainable content therein may be increased.

At atypical 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 above results also give insight to the benefits of co-feeding a pre-hydrotreated sustainable feed subjected — only to degassing/stabilisation, or of co-feeding a non-pre-hydrotreated sustainable feed, such as a fatty feed. 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

N 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

N optimise the product slate e.g. based on market demand, availability of sustainable co-feeds

E 30 and/or their quality. <

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I 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 liguefied 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 pre- hydrotreatment followed by gas-liquid separation and further fractionation. Certain characteristics of the thus obtained pre-hydrotreated renewable feed R1 and pre- hydrotreated 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 pre- hydrotreated 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.

FE

IBP, °C (initial boiling point) 268 200

T50, °C (50 vol-% recovered) 294

FBP, °C (final boiling point) 320 350

Total paraffins, wt.-% 100 72

Hydrocarbons, wt.-% 100 100

C12-C25, wt.-% 99 95 - fasan] [C

From Table 3 it can be seen that the pre-hydrotreated renewable and circular feeds have & high n-paraffin contents, over 60% of the total paraffin content, and boil in the middle distillate range. Incorporating this kind of pre-hydrotreated renewable and/or circular feeds

N in the hydrotreatment feed of the present process may hence be expected to increase yield

N 15 of and sustainable content in the middle distillate range. Furthermore the data in Table 3

E illustrates how the renewable and circular molecules would be distributed in the different <t fractions recovered in the present process if the conventionally purified glyceridic feed of 3 animal fat/vegetable oil origin and/or the conventionally purified liquefied waste plastic

O obtained by thermal degradation/pyrolysis were incorporated directly in the hydrotreatment feed, i.e. without subjecting to a pre-hydrotreatment. Depending on the incorporation rate of the sustainable feeds in the hydrotreatment feed, the cold flow properties of the middle distillate range products may decrease significantly, and may limit their blending ratio or even prevent their use in certain end-uses such as in winter-grade diesel fuels or in aviation fuel. However, due to the high paraffinicity of the renewable and circular content, whether introduced as pre-hydrotreated and/or directly into the hydrotreatment feed, the middle distillate range fractions separated from the hydrotreatment effluent and enriched in the sustainable content, have improved isomerisation-eligibility so that higher total isoparaffin contents and higher branching degrees may be reached in the hydroisomerisation step.

EXAMPLE 3 — Effect of the sustainable content on yields and biogenic carbon contents of the middle distillate fractions

In the following, the effect of the sustainable content on the yields and biogenic carbon contents of different middle distillate fractions is studied. The feeds and process were as described in Example 1, with the exception that a fraction boiling from about 180 to about 360 °C according to ASTM D2887-19e1 (SimDis), corresponding approximately to 160- 340°C according to EN ISO 3405, was investigated as the middle distillate range. This — middle distillate range was fractionated in a batch distillation unit into 180-300 *C, 300-320 °C, 320-340 °C and 340-360 °C fractions (SimDis) to investigate which fraction(s) contribute the most to the cold property decrease. Fraction yields from the batch distillation are presented in Table 4, together with the biogenic carbon content of each fraction, based on the total weight of carbon (TC) in the fraction (EN 16640:2017).

Table 4. Yields (wt.-%) and biogenic carbon contents (wt.-%, EN 16640:2017) of the middle distillate fractions from the batch distillation. fraction

SN | [1] |]

N content, wt.-% content, wt.-% : : ;

J

N From Table 4 it can be seen that, when compared to the corresponding fraction obtained

N by an otherwise similar process using petroleum reference feed Pr, the yield of 300-320 °C and 320-340 °C fractions has almost doubled. Still, their summed amount accounts for

<45wt.-% of the total middle distillates yield. Even if the whole fraction boiling within 300- 340 °C would be subjected to hydroisomerisation, the required isomerisation capacity compared to the total volume of the hydrotreatment feed would be far less than e.g. in conventional HVO plants. Furthermore, by selecting cut-points to cover only the content benefiting most from the hydroisomerisation, the volume could be further reduced.

Table 4 also shows the biogenic carbon content concentration across these fractions. Most of the biogenic carbon content originating from the animal fat can be estimated to reside within boiling point range 300-320 °C, whereas the biogenic carbon content originating from the crude tall oil mostly resides within boiling point range 320-340 °C. The renewable content is highly enriched within the boiling point range 300-340 °C. It is also a boiling point range that may be easily upgraded to be utilised as a blend component in aviation and/or diesel fuel compositions.

Example 4 — Effect of the sustainable content on cold flow properties of the middle distillate fractions

In the following, the effect of the sustainable content on cold flow properties of different middle distillate fractions is studied. Cloud points of the different middle distillate fractions recovered in Example 3 and their combinations were measured according to ASTM D7689- 2021. The results are reported in Table 5.

Table 5. Cloud points of the different middle distillate fractions. fraction g

S

; : a | wwe | a | 08 | n 00 s [wwe | s |e so

Po [wwe | a [0 010"

S

N 20 From Table 5 it can be seen that incorporation of sustainable content, when compared to the corresponding fraction obtained by otherwise similar process using petroleum reference feed Pr, has the greatest impact on the cloud point of the 300-320°C fraction. This is believed to be caused especially by the increased C18 n-paraffin content, as octadecane has a boiling point in this range (about 317*C), and is solid at room temperature (melting point 28-30°C). If only the 300-320°C fraction was subjected to hydroisomerisation, very — limited isomerisation capacity would be needed, but the cloud point of the rest of the middle distillate range would improve significantly when compared to the full 180-360*C range, namely from 1°C to -5°C when using S1 containing hydrotreatment feed, and from -4°C to -7°C when using S2 containing hydrotreatment feed. Excluding the 300-320°C fraction from the remaining middle distillate range and its effect on the cloud point is illustrated in Figure 2, where 450 represents 180-300°C fraction, 430 represents 300-320°C fraction, 440 represents 320-360°C fraction, and x indicates presence and — absence of the fraction in the mixture whose cloud point is measured and reported.

Selection of the middle distillate fraction(s) to be subjected to the hydroisomerisation may be adjusted based on the available isomerization unit capacity, and/or on the biogenic — carbon content of the middle distillate fraction(s).

The 300-340 °C range is rich in renewable n-paraffin content that can be isomerized to improve the stream's cold flow properties. Compositions of 300-320 °C, 320-340 °C and 340-360 °C fractions are shown in table 6, 7 and 8, respectively.

Table 6. Composition of 300-320°C fraction as determined by GCxGC-FID/GCxGC-MS. ~C17-C20 S1 % S2

Commer | Ot 0 1 n 5 paraffins, wt:wt

E 20 Table 7. Composition of 320-340 °C fraction as determined by GCxGC-FID/GCxGC-MS. s 320-340 °C 100 wt.-% Pr 75 wt.-% P + 25 wt.-% | 75 wt.-% P + 25 wt.- = ” homies | |e |e peek @ ew paraffins, wt:wt

Table 8. Composition of 340-360 °C fraction as determined by GCxGC-FID/GCxGC-MS. ~C20-C23

Homea | oe | a ma 1 1 N paraffins, wt:wt

From Table 6 it can be seen that incorporation of sustainable content, when compared to the reference i.e. corresponding fraction obtained by otherwise similar process using petroleum reference feed Pr, has a huge influence on the contents of total paraffins, approximately doubling their content, in the 300-320 *C fraction. At the same time the content of isoparaffins has dropped to one third or fourth. Conseguently the weight ratio of isoparaffins to n-paraffins has dropped significantly, reflecting the dramatic decline in the cold properties. From Table 7 it can be seen that incorporation of sustainable content, when compared to the reference fraction, does not have a remarkable influence on the contents of total paraffins, aromatics and naphthenes in the 320-340 °C fraction. However, based on the total paraffins, the content of isoparaffins is reduced to less than half, and consequently the weight ratio of isoparaffins to n-paraffins has dropped to one third or fourth. From Table 8 it can be seen that, when compared to the reference fraction, the influence on the contents of total paraffins, aromatics and naphthenes in the 340-360 °C fraction is not remarkable, = 15 and there's only a modest decrease in the share of isoparaffin based on the total paraffins.

N At the same time the weight ratio of isoparaffins to n-paraffins has dropped to half, only.

N

ES Example 5 — Response of a middle distillate fraction to conventional cold flow z additive = The process as described in Example 1 was followed, except that conventionally purified © 20 (heat treated and bleached) animal fat (AF) was co-fed to the hydrotreatment with a similar

O petroleum feed as Pr, in amounts providing the biogenic carbon contents as indicated in

Table 9. Some of the properties of the fractions recovered as the second middle distillate fraction are reported in Table 9. As reference, a fraction obtained by otherwise similar process but using 100% petroleum feed as the hydrotreatment feed was provided. After analysing the characteristics, an optimal dosage of a conventional cold flow additive was added to each fraction, and CFPP was measured again. In Table 9 the maximum CFPP improvement achieved by the cold flow additive is reported for each fraction. Additionally in

Fig 3 are reported CFPP results obtained by adding increasing dosages of the same cold flow additive to the biogenic carbon containing fractions.

Table 9. Certain characteristics of the second middle distillate fractions obtained by the present process using hydrotreatment feeds containing petroleum feed and AF, and of a middle distillate fraction obtained by otherwise similar process using 100% petroleum feed.

Distillation characteristics were determined according to EN ISO 3405-2019, cloud points according to ASTM D7689-2021, and CFPP according to EN 116:2018-04. Chemical compositions, including contents of n-paraffins (nP), were determined by GCxGC-

FID/GCxGC-MS.

TEE [wm = the fraction, based on total 93 8.3 carbon (wt-%), EN 16640:2017 2 ; 5 = Max CFPP improvement [st [-1-[- < additive, °C

From Table 9 it can be seen, that co-feeding the petroleum feed and the animal fat led to increase in n-paraffin content, especially in n-C18 content, in the recovered fractions, and hence the cloud point values deteriorated. Typically cloud point and CFPP of diesel range fractions having sustainable content are approximately the same, and such fractions do not respond well even to elevated cold flow additive dosages. By incorporating a conventional cold flow additive to the fractions having renewable content it was possible to improve the

CFPP values by a similar magnitude as of the reference fraction obtained using 100% petroleum feed. This is surprising, especially as the n-paraffins introduced by the renewable content were not evenly spread over the carbon number distribution, but a clear peak in the n-C18 content was observed. However, the CFPP improvement was achieved only for the fractions having significantly wider boiling ranges, expressed as difference between T90 and T20, and also longer distillation tails, expressed as difference between FBP and T90, than those of the 100% petroleum reference. The results for the biogenic carbon containing fractions are presented also in Figure 3 showing CFPP values as the function of cold flow additive (flow improver) dosage. From Figure 3 it can be seen that the biogenic carbon containing fractions “9.3% BIO” and “8.3% BIO” having widest boiling ranges, expressed as difference between T90 and T20, and also longest distillation tails, expressed as difference between FBP and T90, exhibited good flow improver response. The CFPP behaviour of the biogenic carbon containing fraction “9.0% BIO, was as a skilled person would expect for a diesel range fraction having renewable content, in other words this fraction did not respond to the cold flow additive at all, despite having similar T90-T20 boiling range and slightly longer distillation tail compared to the 100% petroleum reference.

The surprising findings of Example 5 support the benefits of the present process, which allows to recover at least one middle distillate fraction as a relatively wide cut, as it is actually preferred that the middle distillate fraction to be sent to the hydroisomerisation is narrower & so as to facilitate optimisation of the hydroisomerisation conditions.

N

N Various embodiments have been presented. It should be appreciated that in this document,

ES words comprise, include and contain are each used as open-ended expressions with no

I intended exclusivity. a

J 30 The foregoing description has provided by way of non-limiting examples of particular

S implementations and embodiments of the invention a full and informative description of the

O 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.

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Claims

1. A process for producing hydrocarbon fractions, the process comprising: a) providing 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 first separation stage, and recovering from the first separation stage at least a naphtha fraction, a first middle distillate fraction, a second middle distillate fraction, and a first separation stage bottom, — wherein the first middle distillate fraction is a lower boiling middle distillate fraction and the second middle distillate fraction is a higher boiling middle distillate fraction, d) subjecting a hydroisomerisation feed comprising at least a portion of the first or the second middle distillate fraction to hydroisomerisation in a hydroisomerisation reactor in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, — e) introducing at least a portion of the hydroisomerisation effluent into a second separation stage, and recovering from the second separation stage at least one or more aviation fuel range fraction and/or diesel fuel range fraction.

2. The process according to claim 1, wherein the first middle distillate fraction has a boiling point range within a range from 100°C to 330°C and the second middle distillate fraction has a boiling point range within a range from 130°C to 400°C (EN ISO 3402-2019), preferably the first middle distillate fraction has a boiling point range within a range from 120°C to 310°C and the second middle distillate fraction has a boiling point range within a range from 150°C to 380°C (EN ISO 3402-2019), more preferably the first middle distillate & fraction has a boiling point range within a range from 130°C to 310°C and the second middle distillate fraction has a boiling point range within a range from 160°C to 370°C (EN ISO i 3402-2019). N

E 3. The process according to claim 1 or 2, wherein the first or the second middle distillate < fraction incorporated in the hydroisomerisation feed has a difference between T95 and T5 3 temperatures (EN ISO 3405-2019) at most 150°C, preferably at most 120°C, more & 30 preferably at most 100°C; or a difference between T95 and T5 temperatures (EN ISO 3405- N 2019) within a range from 10°C to 150°C, preferably from 15°C to 120°C, more preferably from 20°C to 100°C.

4. The process according to any one of the preceding claims, wherein: — the hydroisomerisation feed comprises at least a portion of the second middle distillate fraction, at least an aviation fuel range fraction is recovered from the second separation stage, and the aviation fuel range fraction and at least a portion of the first middle distillate fraction are introduced into an aviation fuel range pool; or — the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, at least an aviation fuel range fraction is recovered from the second separation stage, and introduced into an aviation fuel range pool.

5. The process according to any one of the preceding claims, wherein step c) further comprises recovering from the first separation stage a further middle distillate fraction.

6. The process according claim 5, wherein the further middle distillate fraction has a boiling point range within a range from 100°C to 300°C, the first middle distillate fraction has a boiling point range within a range from 120*C to 330*C, and the second middle distillate fraction has a boiling point range within a range from 150*C to 400*C (EN ISO 3405-2019); and optionally at least a portion of the further middle distillate fraction is introduced into an aviation fuel range pool and/or into a cold climate diesel fuel range pool.

7. The process according to any one of the preceding claims, wherein: — at least a portion of the second middle distillate fraction is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive; and — preferably the hydroisomerisation feed comprises at least a portion of the first middle distillate fraction, at least a diesel fuel range fraction is recovered from the second separation stage and at least a portion thereof is introduced into a cold climate diesel fuel 2 range pool. O N

N 8. The process according to any of the preceding claims, wherein the second middle ES 25 distillate fraction has T5 and T95 temperatures (EN ISO 3405-2019) within a range from - 160°C to 380°C, preferably within a range from 170°C to 360°C, and a difference between a > T90 and T20 temperatures (EN ISO 3405-2019) at least 68°C, preferably at least 70°C, and <t 5 optionally a difference between FBP and T90 temperatures (EN ISO 3405-2019) at least 2 15°C, preferably at least 16°C. O N

9. The process according to any one of the preceding claims, wherein the first 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; or the first separation stage bottom has an initial boiling point within a range from 300°C to 420°C (EN ISO 3405-2019), preferably within a range from 320°C to 410°C, more preferably within a range from 340°C to 400°C.

10. The process according to any one of the preceding claims, wherein a residual marine fuel component is recovered from the first separation stage bottom, preferably by splitting a portion from the first separation stage bottom.

11. The process according to any one of the preceding claims, wherein the process further comprises f) subjecting a heavy hydroconversion feed comprising at least a portion of the first separation stage bottom, and optionally at least a portion of the second middle distillate, to hydroconversion in a hydroconversion reactor in the presence of hydrocracking and/or hydroisomerisation catalyst(s) to obtain a hydroconversion effluent, and optionally co-feeding at least a portion of the hydroconversion effluent with the hydrotreatment effluent to the first separation stage.

12. The process according to any one of the preceding claims, wherein in step b) the — hydrotreatment feed is subjected to hydrotreatment in the hydrotreatment reactor in the presence of the hydrotreatment catalyst and a dewaxing catalyst to obtain the hydrotreatment effluent.

13. The process according to any one of the preceding claims, wherein at least a portion of the naphtha fraction and/or of a further middle distillate fraction optionally recovered from — the first separation stage is/are introduced into a gasoline fuel range pool, or used as a steam cracker feed; and/or wherein fuel gases and/or a light naphtha fraction is/are further recovered from the first and/or the second separation stage, and at least a portion thereof 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. N N 25

14 The process according to any one of the preceding claims, wherein the N 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 3 85 wt.-%. 3 Q

15. The process according to any one of the preceding claims, wherein the petroleum x 30 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.

16. The process according to any one of the preceding claims, wherein at least one or more, preferably at least two or more, more preferably at least three or more of the hydrotreatment reactor, the first separation stage, the hydroisomerisation reactor, the second separation stage, and/or the hydroconversion reactor are as originally configured to treat a petroleum feed.

17. The process according to any one of the preceding claims, wherein step a) comprises: at) combining a petroleum feed 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, and/or a2) 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-hydrotreatment in a pre-hydrotreatment reactor in the presence of a pre-hydrotreatment catalyst to obtain a pre-hydrotreatment effluent, and co-feeding a petroleum feed to the pre-hydrotreatment reactor and/or combining a petroleum feed with at least a fraction of the pre-hydrotreatment effluent, to obtain the hydrotreatment feed having petroleum content as well as renewable and/or circular content.

18. The process according to any one of the preceding claims, wherein 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-hydrotreatment JN in a pre-hydrotreatment reactor in the presence of a pre-hydrotreatment catalyst to obtain S a pre-hydrotreatment effluent, and combining a petroleum feed with at least a fraction of the A 25 — pre-hydrotreatment effluent to obtain the hydrotreatment feed having petroleum content as n well as renewable and/or circular content. N E

19. The process according to claim 17 or 18, wherein step a) comprises feeding the pre- < hydrotreatment effluent to a pre-hydrotreatment fractionation to recover one or more pre- 3 hydrotreatment distillate(s) and a pre-hydrotreatment fractionation bottom, combining a O N 30 petroleum feed with the pre-hydrotreatment fractionation bottom to obtain the N hydrotreatment feed; the process further comprising:

h) feeding the one or more pre-hydrotreatment 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 i) optionally recovering from the catalytic conversion effluent at least an aviation fuel component and/or a diesel fuel component.

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