WO2025141244A1

WO2025141244A1 - A process for producing diesel boiling range fraction(s) having sustainable content

Info

Publication number: WO2025141244A1
Application number: PCT/FI2024/050729
Authority: WO
Inventors: Alli KOIVISTO; Eerika VUORIO; Jarno Kohonen; Eetu KARI; Petro SIREGAR
Original assignee: Neste Oyj
Current assignee: Neste Oyj
Priority date: 2023-12-27
Filing date: 2024-12-20
Publication date: 2025-07-03
Anticipated expiration: 2026-06-27

Abstract

A process for producing a diesel boiling range fraction having sustainable content is provided In the process, from 60 to 99 wt.-% of a petroleum feed having T5 and T95 temperatures (EN ISO 3405-2019) within a range from 180°C to 420°C, and a difference between T95 and T5 temperatures (EN ISO 3405-2019) within a range from 70°C to 200°C, and 1 to 40 wt.-% of a renewable and/or circular feed are combined to obtain a hydrotreatment feed having petroleum content as well as renewable and/or circular content. The hydrotreatment feed is subjected to hydrotreatment to obtain a hydrotreatment effluent that is introduced into a separation stage, wherefrom at least a diesel boiling range fraction as the separation stage bottom is recovered. A portion of the diesel boiling range fraction is then subjected to hydroisomerisation, and at least a second diesel boiling range fraction recovered from the hydroisomerisation effluent.

Description

A PROCESS FOR PRODUCING DIESEL BOILING RANGE FRACTION(S) HAVING SUSTAINABLE CONTENT

TECHNICAL FIELD

The present disclosure generally relates to a process for producing diesel boiling range fraction(s) having sustainable content. The disclosure relates particularly, though not exclusively, to a process for producing a diesel boiling range fraction usable in a diesel fuel range pool.

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 carbon footprint in the transportation and petrochemical industry. At the same time the demand for hydrocarbons in these and other fields is increasing worldwide, and the crude oil reserves are vanishing. Accordingly, interest towards the use of sustainable materials in hydrocarbon production is growing.

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

In addition to the concepts dedicated for processing fully biogenic products, for tackling global warming and vanishing crude oil reserves, as well as for meeting the above- mentioned needs, further solutions for industrial processes and products are urgently needed. In this regard, co-feeding of sustainable feed streams into existing petroleum refineries has a growing interest not least because of the existing infrastructure, allowing almost instant implementation. One of 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 crude oil to gasoline and propylene as the key products. However, FCC technology requires catalyst regeneration which involves high CO2 emissions, even 25-35% of the total CO2 emissions of a conventional petroleum refinery. Evidently, there is a continuous need to develop improvements in co-processing.

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 product(s) of higher value. A further aim is to control or even improve the cold properties of diesel boiling range fraction(s) 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 a diesel boiling range fraction, the process comprising: a) combining from 60 to 99 wt.-%, preferably from 65 to 97 wt.-%, more preferably from 70 to 92 wt.-% of a petroleum feed, and from 1 to 40 wt.-%, preferably from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-% of a renewable and/or circular feed to obtain a hydrotreatment feed having petroleum content as well as renewable and/or circular content, wherein the petroleum feed has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 180°C to 420°C, a difference between T95 and T5 temperatures (EN ISO 3405- 2019) within a range from 70°C to 200°C, and preferably a T50 temperature (EN ISO 3405- 2019) within a range from 290°C to 350°C, 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 the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least a diesel boiling range fraction as the separation stage bottom, and d) subjecting a hydroisomerisation feed comprising a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation in a hydroisomerisation reactor in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, and recovering from the hydroisomerisation effluent at least a second diesel boiling range fraction having a lower cloud point compared to the diesel boiling range fraction recovered in step c).

The inventors have found the present process and embodiments thereof to provide certain advantages compared to prior art processes co-processing petroleum feed and sustainable i.e. renewable and/or circular feed. The advantages are related e.g to reduced GHG emissions and carbon footprint, as well as to reduced dependence from the diminishing petroleum sources, especially in the transportation but also in the petrochemical sector. The advantages are also related to an improved overall economy of the process, improved flexibility regarding obtainable products, and higher overall value of the product slate. Incorporation of renewable and/or circular content in a hydrotreatment feed may be expected to increase n-paraffin content of the produced fraction(s), particularly of the produced middle distillate(s), which is beneficial for their cetane number, but foreseen detrimental to their cold properties. However, with the help of the present process cold property 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 diesel boiling range fraction exhibiting improved response to conventional cold flow additive(s) is obtainable in step c).

Subjecting only a portion, or an aliquot, of the diesel boiling range fraction recovered in step c) to hydroisomerisation is particularly beneficial, as allowing flexible production of fractions for different diesel grades and even for aviation fuel, with limited hydroisomerisation capacity. This is desired, as conventional oil refineries have typically far less of hydroisomerisation capacity than hydrotreatment or cracking capacity. Furthermore, the limited hydroisomerisation capacity may be utilised to provide a middle distillate of overquality in terms of cold properties, and such middle distillate may be blended with at least a portion of the remaining diesel boiling point fraction recovered in step c) to provide a diesel fuel or component having desired cold properties. Finally, as middle distil late(s) having the desired cold properties may be provided by subjecting only a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation, significant yield benefits may be reached. E.g. hydroisomerisation may reduce middle distillate(s) yield by about 2%.

In certain preferred embodiments, at least 10 wt.-%, preferably at least 20 wt.-%, more preferably at least 30 wt.-%, and at most 80 wt.-%, preferably at most 60 wt.-%, more preferably at most 50 wt.-%, of the diesel boiling range fraction recovered in step c) is subjected to hydroisomerisation.

In certain preferred embodiments, the second diesel boiling range fraction has at least 5 °C, preferably at least 10 °C, more preferably at least 15 °C, even more preferably at least 25 °C lower cloud point (ISO 3015-2019) compared to the diesel boiling range fraction recovered in step c), and advantageously at least a portion of the second diesel boiling range fraction recovered in step d) is blended with a portion of the diesel boiling range fraction recovered in step c).

In certain preferred embodiments, step d) comprises recovering from the hydroisomerisation effluent an aviation fuel range fraction as a distillate, and preferably the second diesel fuel range fraction as a distillation bottom.

The above-mentioned advantages may be attained with reduced costs, especially when utilising existing assets of a petroleum refinery. Hence, in certain preferred embodiments, the hydrotreatment reactor in step b), the hydrotreatment catalyst in step b), the hydroisomerisation reactor in step d), and/or the hydroisomerisation catalyst in step d) are as originally configured to treat a petroleum feed.

When the specified petroleum feed and the renewable and/or circular feed are coprocessed according to the present disclosure, a diesel boiling range fraction having renewable and/or circular content is obtained in step c) with at least one or more of the following benefits: good yield and energy-savings, reduced risk of too low flash point for diesel fuels, sufficient density not limiting the blending ratio when targeting diesel fuel meeting EN 590 Table 1 specification, better cold properties than expected in view of the increased n-paraffin content, and a relatively broad boiling range especially expressed as a difference between T90 and T20 temperatures (EN ISO 3405-2019) enhancing cold flow additive response.

In certain preferred embodiments, the diesel boiling range fraction recovered in step c) of the present process has at least one or more of the following:

- a T5 temperature (EN ISO 3405-2019) within a range from 170°C to 270°C, preferably from 180°C to 260°C, more preferably from 190°C to 250°C; and/or

- T5 and T95 temperatures (EN ISO 3405-2019) within a range from 170°C to 380°C, preferably within a range from 180°C to 370°C, more preferably from 190°C to 360°C; and/or - a biogenic carbon content within a range from 1 to 40 wt.-%, based on the total weight of carbon (TC) in the diesel boiling range fraction (EN 16640:2017), preferably within a range from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-%; and/or

- a difference between T90 and T20 temperatures (EN ISO 3405-2019) at least 68°C, preferably at least 70°C, more preferably at least 72°C; and/or

- a weight-ratio of C17 n-paraffin to C18 n-paraffin within a range from 0.80 to 1.30, preferably from 0.85 to 1 .25, more preferably from 0.90 to 1 .20; and/or

- a total content of n-paraffins within a range from 12 wt.-% to 60 wt.-%, preferably from 15 wt.-% to 55 wt.-%, more preferably from 20 wt.-% to 50 wt.-%; and/or

- a kinematic viscosity at 40 °C (EN ISO 3104-2020) within a range from 1 .5 to 5.5 mm2/s, preferably from 1 .8 to 5.0 mm2/s, more preferably from 2.0 to 5.0 mm2/s; and/or

- a density at 15 °C (EN ISO 12185-1996) within a range from 820 to 850 kg/m3, preferably from 820 to 845 kg/m3, more preferably from 825 to 845 kg/m3.

In certain preferred embodiments, a portion of the diesel boiling range fraction recovered in step c) is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive.

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

Fig. 2 shows n-paraffin distribution of two different diesel boiling range fractions of step c) according to example embodiments of the present disclosure, and of three comparative diesel boiling range fractions. Fig. 3 shows the response to two conventional cold flow additives of diesel boiling range fractions of step c) according to example embodiments of the present disclosure (Fig 3b, Fig 3c), and of a comparative diesel boiling range fraction (Fig. 3a).

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.

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. Typically, such diesel fuel range fractions boil, i.e. have IBP and FBP, within a range from about 130 °C to about 380 °C, such as within a range from about 160 °C to about 380 °C, as determined according to EN ISO 3405-2019. By temperate climate diesel fuel range fraction or pool (or fuel) reference is herein made to a diesel fuel range fraction or pool (or fuel) meeting one or more of the cold filter plugging point requirements (CFPP) laid down in EN 590:2022 Table 2, and by cold climate diesel fuel range fraction or pool (or fuel) reference is herein made to a diesel fuel range fraction or pool (or fuel) meeting one or more of the CFPP requirements and/or cloud point (CP) requirements laid down in EN 590:2022 Table 3 for arctic and severe winter climate diesels.

As used in the context of this disclosure, gasoline fuel range fraction or pool, or naphtha fraction, refers to hydrocarbon compositions suitable - as such or after stabilisation - for use, at least as blend components, in fuels meeting standard specifications for gasoline fuels, such as specifications laid down in EN 228:2012 + A1 :2017. Typically, as stabilised, such gasoline fuel range or naphtha fractions boil, i.e. have IBP and FBP, within a range from about 20 °C to about 220 °C, preferably from about 25 °C to about 210 °C, as determined according to EN ISO 3405-2019. By light naphtha fraction reference is herein made to a fraction comprising C4 or heavier and having FBP at most about 180 °C, typically requiring stabilisation before use in gasoline fuels.

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

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 GO) method was run as generally disclosed in UOP 990-2011 and by Nousiainen M. in the experimental section of his Master's Thesis Comprehensive two-dimensional gas chromatography with mass spectrometric and flame ionization detectors in petroleum chemistry, University of Helsinki, August 2017, with the following modifications. The GCxGC was run in reverse mode, using a semipolar column (Rxi17Sil) first and a non-polar column (Rxi5Sil) thereafter, followed by FID detector, using run parameters: carrier gas helium 31 .7 cm/s (column flow at 40 °C 1.60 ml/min); split ratio 1 :350; injector 280 °C; Column T program 40 °C (0 min) - 5 °C/min - 250 °C (0 min) - 10 °C/min - 300 30 °C (5 min), run time 52 min; modulation period 10 s; detector 300 °C with H2 40 ml/min and air 400 ml/min; makeup flow helium 30 ml/min; sampling rate 250 Hz and injection size 0.2 microliters. Individual compounds were identified using GCxGC-MS, with MS-parameters: ion source 230 °C; interface 300 °C; scan range 25 - 500 amu; event time (sec) 0.05; scan speed 20000. Commercial tools (Shimadzu's LabSolutions, Zoex's GC Image) were used for data processing including identification of the detected compounds or hydrocarbon groups, and for determining their mass concentrations by application of response factors relative to n- heptane to the volumes of detected peaks followed by normalization to 100 wt.-%. Olefins were lumped with naphthenes and heteroatomic species with aromatics, unless separately reported. The limit of quantitation for individual compounds of this method is 0.1 wt.-%. Chemically, the renewable or non-renewable (such as petroleum) origin of any organic compound, including hydrocarbons, can be determined by suitable method for analysing the content of carbon from renewable sources e.g. DIN 51637:2014-02, ASTM D6866-2022, or EN 16640:2017. Said methods are based on the fact that carbon atoms of renewable or biological origin comprise a higher number of unstable radiocarbon (14C) atoms compared to carbon atoms of fossil origin. Therefore, it is possible to distinguish between carbon compounds derived from renewable or biological sources and carbon compounds derived from non-renewable (such as petroleum) sources by analysing the ratio of 12C and 14C isotopes. Thus, a particular ratio of said isotopes can be used as a “tag” to identify a renewable carbon compound and differentiate it from non-renewable carbon compounds. The isotope ratio does not change in the course of chemical reactions. Therefore, the isotope ratio can be used for identifying renewable carbon compounds and distinguishing them from non-renewable carbon compounds in feeds, 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 hydrotreatment reactions may include removal of oxygen from oxygenated hydrocarbons as water i.e. hydrodeoxygenation (HDO), sulphur from organic sulphur compounds as dihydrogen sulphide (H2S), i.e. hydrodesulphurisation, (HDS), nitrogen from organic nitrogen compounds as ammonia (NH3), i.e. hydrodenitrogenation (HDN), halogens, for example chlorine from organic chloride compounds as hydrochloric acid (HCI), i.e. hydrodechlorination (HDCI), and/or metals by hydrodemetallization; and/or hydrogenation of olefinic bonds to saturated bonds and/or of aromatics to naphthenes. Depending e.g. on the composition of the hydrotreatment feed, different reactions may occur and/or prevail in the hydrotreatment. Generally, hydrotreatment is capable of converting hydrotreatment feeds of varying compositions to more pure materials, by reducing content of heteroatoms, metals, olefins, aromatics and/or other less desired compounds in the hydrotreatment feed. Hydrotreatment may also involve certain side reactions, such as hydrocracking reactions.

As used herein, wherever the reaction steps are defined to take place in “reactors”, such as the hydrotreatment 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 a diesel boiling range fraction, the process comprising: a) combining from 60 to 99 wt.-%, preferably from 65 to 97 wt.-%, more preferably from 70 to 92 wt.-% of a petroleum feed, and from 1 to 40 wt.-%, preferably from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-% of a renewable and/or circular feed to obtain a hydrotreatment feed having petroleum content as well as renewable and/or circular content, wherein the petroleum feed has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 180°C to 420°C, a difference between T95 and T5 temperatures (EN ISO 3405- 2019) within a range from 70°C to 200°C, and preferably a T50 temperature (EN ISO 3405- 2019) within a range from 290°C to 350°C, 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 the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least a diesel boiling range fraction as the separation stage bottom, and d) subjecting a hydroisomerisation feed comprising a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation in a hydroisomerisation reactor in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, and recovering from the hydroisomerisation effluent at least a second diesel boiling range fraction having a lower cloud point compared to the diesel boiling range fraction recovered in step c).

The present process provides middle distillate(s), particularly diesel boiling range fraction(s) having renewable and/or circular content with improved overall economy of the process and with higher overall value of the product(s). At the same time GHG emissions and dependence from the diminishing petroleum sources is reduced. Incorporation of renewable and/or circular content in the hydrotreatment feed is foreseen to increase n-paraffin content in the product fractions as upon hydrotreatment e.g. typical fatty materials and liquefied waste plastics become rich in paraffins whereof well over 50 wt.-% may be n-paraffins. While n-paraffins are good for cetane number, increase in their content is generally expected to deteriorate cold properties. For example C18 n-paraffin (octadecane) has a boiling point in diesel range (about 317°C), and is solid at room temperature (melting point 28-30°C). However, the present inventors have found that by subjecting a petroleum feed and a renewable and/or circular feed to hydrotreatment as specified herein, a diesel boiling range fraction is obtainable in step c) with better cold properties than expected, in good yields, and with reduced risk of too low flash point. Embodiments of the present process also enable even simultaneous production of a temperate climate diesel fuel component, as well as a cold climate diesel fuel component, and even an aviation fuel range fraction. Surprisingly the inventors also found that the diesel boiling range fraction as obtainable in step c) of the present process exhibits improved response 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 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 present process involves combining a petroleum feed, and a renewable and/or circular feed to obtain a hydrotreatment feed having petroleum content as well as renewable and/or circular content. The petroleum feed and the renewable and/or circular feed may be e.g. cofed via separate inlets to same hydrotreatment catalyst bed, or e.g. in this order to catalyst beds following one after another, to form the hydrotreatment feed in-situ in the hydrotreatment reactor. This is perhaps the simplest way to provide a hydrotreatment feed having petroleum content as well as renewable and/or circular content, as not even a feed blending vessel is needed. Alternatively, the petroleum feed and the renewable and/or circular feed may be co-fed as a preformed blend. The petroleum feed may be seen as a diluent for the renewable and/or circular feed, thereby controlling temperature increase in the hydrotreatment reactor caused by exothermic hydrotreatment reactions, particularly by hydrodeoxygenation. As the share of the renewable and/or circular feed in the hydrotreatment feed is from moderate to low, there is no need to recycle a portion of the hydrotreatment effluent to the hydrotreatment reactor to further mitigate temperature increase caused by exothermic reactions. In otherwords, the capacity of the hydrotreatment reactor may be fully utilised for processing the hydrotreatment feed consisting of the petroleum feed and the renewable and/or circular feed. If needed, additional exotherm control may be provided e.g. by cold hydrogen quenching, and/or by loading a less active hydrogenation catalyst topmost in the reactor. Furthermore, the moderate to low share of the renewable and/or circular feed in the hydrotreatment feed allows to introduce into conventional petroleum refinery units even highly challenging feedstocks, without major corrosion concerns, and to maintain the hydrotreatment efficiency, including heteroatom content reduction, olefins saturation and dearomatization, at a sufficient level.

As the petroleum feed is the main component in the hydrotreatment feed, the hydrotreatment feed is expected to have a moderately elevated sulphur content. Consequently, oxygen atom cleavage, i.e. deoxygenation, via decarboxylation and decarbonylation (in the following “decarb”) reactions can be expected to be favoured over hydrodeoxygenation, due to the elevated sulphur content. Oxygen atoms are typically abundant especially in the renewable feeds, particularly in vegetable oil(s), animal fat(s), microbial oil(s), and/or lignocellulose-derived biocrude(s), so when using these as co-feeds with the petroleum feed, levels of formed CO and CO2 may be expected to increase, although not remarkably, as the share of the renewable and/or circular feed is at most moderate. This is beneficial, as unlike CO2 which may be efficiently removed from reactor effluent’s gaseous phase using conventional purification technologies, such as sweetening removing both H2S and CO2, CO may accumulate in a recycle hydrogen stream optionally recovered from a gaseous stream separated from the hydrotreatment effluent, thereby limiting e.g. how much of the recycle hydrogen stream may actually be recycled back to the present process or to refinery’s other hydrotreatment, hydroisomerisation and/or hydrocracking units. Deoxygenation partially via decarb route may be seen as beneficial also for the cold properties of the obtained diesel boiling range fraction, as shortening a carbon chain even by one carbon atom lowers the melting point by several Celsius degrees, and additionally for cold flow additive response, as a wider carbon chain distribution, particularly wider n-paraffin distribution, was found to have beneficial impact on the cold flow additive response of the diesel boiling range fraction recovered in step c).

In the present process, the hydrotreatment feed comprises a high share of petroleum feed, namely from 60 to 99 wt.-%, preferably from 65 to 97 wt.-%, more preferably from 70 to 92 wt.-% of a petroleum feed, and only from 1 to 40 wt.-%, preferably from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-% of a renewable and/or circular feed, based on the total weight of the hydrotreatment feed. This is advantageous, as the renewable and/or circular feeds may be somewhat acidic, so the present process may be run without significant corrosion concerns regarding metallurgy of the hydrotreatment reactor. Furthermore, petroleum feeds are known to have significant sulphur contents. By incorporating a high share of petroleum feed in the hydrotreatment feed, the hydrotreatment catalyst may remain sufficiently sulphided and hence active even without separate sulphur spiking. Additionally, petroleum contains various hydrocarbons of the paraffinic, naphthenic, and aromatic compound classes, and with a very broad molecular weight range. Hence, the petroleum content may be regarded as beneficial also for product property reasons, for example providing cyclic compounds to the diesel boiling range fraction, thereby compensating for the influence of the renewable and/or circular content and helping to meet e.g. the minimum requirement for density at 15°C of 820.0 kg/m3 laid down in EN 590:2022 Table 1.

The present process utilises a petroleum feed having T5 and T95 temperatures (EN ISO 3405-2019) within a range from 180°C to 420°C, a difference between T95 and T5 temperatures (EN ISO 3405-2019) within a range from 70°C to 200°C, and preferably a T50 temperature (EN ISO 3405-2019) within a range from 290°C to 350°C. In certain preferred embodiments, the petroleum feed has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 200°C to 400°C, preferably from 220°C to 400°C, and a difference between T95 to T5 temperatures (EN ISO 3405-2019) within a range from 75°C to 190°C, preferably from 80°C to 180°C. It is desired for the present process to utilise sufficiently well-defined petroleum feed as the hydrotreatment feed component, not least because of its relatively high share in the hydrotreatment feed. The T95 temperature of the petroleum feed needs to be sufficiently low so as to allow recovery of the diesel boiling range fraction as the separation stage bottom in step c), the diesel boiling range fraction still having suitable density, viscosity, cetane, cold properties and polyaromatics content to allow its use in diesel fuels meeting specifications e.g. as laid down in EN 590:2022. Additionally, recovery of the diesel boiling range fraction as the separation stage bottom provides high energy savings, helping to further reduce GHG emissions and the carbon footprint of the diesel boiling range fraction. A sufficiently high T5 temperature and a sufficiently broad boiling range, as expressed by the difference between T95 and T5 temperatures, reflecting certain level of heaviness of this main component of the hydrotreatment feed, was surprisingly found to have a beneficial influence on the cold properties of the diesel boiling range fraction recovered in step c). More precisely, it was found that if the petroleum feed is too light, even the relatively low shares of the renewable and/or circular feed utilised in the present process may lead to significant deterioration of the cloud point of the diesel boiling range fraction recovered in step c). However, with the carefully selected petroleum feed properties, the cloud point of the obtained diesel boiling range fraction may be essentially the same as that of a diesel boiling range fraction obtained by an otherwise similar process and petroleum feed but without any renewable and/or circular content, or the cloud point may deteriorate but less than expected e.g. in view of high melting points of n-paraffins. The carefully selected petroleum feed properties, and particularly the sufficiently broad boiling range, were also found to contribute to the enhanced response of the diesel boiling range fraction recovered in step c) to conventional cold flow additives, which was not seen at all, or only to a lesser extent when using petroleum feed not having these properties.

In certain preferred embodiments, the petroleum feed has a T50 temperature (EN ISO 3405-2019) within a range from 290°C to 340°C, preferably from 300°C to 340°C; and/or a T95 temperature (EN ISO 3405-2019) within a range from 330°C to 400°C, preferably from 340°C to 390°C. These embodiments reflect the advantageous heaviness of the petroleum feed, hence further contributing to the related benefits.

In certain preferred embodiments, the petroleum feed has a cloud point (ISO 3015-2019) within a range from -10°C to +15°C, preferably from -10°C to +10°C, more preferably from -5°C to +5°C. These embodiments are beneficial, because the diesel boiling range fraction is recovered as the fractionation stage bottom in step c), so its cloud point may be significantly contributed by the cloud point of the petroleum feed.

In certain preferred embodiments, the petroleum feed has a total content of cyclic hydrocarbons (GCxGC-FID/GCxGC-MS) within a range from 40 to 99 wt.-%, preferably from 50 to 95 wt.-%, more preferably from 55 to 90 wt.-%, based on the total weight of the petroleum feed. These embodiments reflect the advantageous heaviness of the petroleum feed, hence further contributing to the related benefits. Additionally, the relatively high share of cyclic hydrocarbons in the petroleum feed is preferred so as to increase the density and energy content of the hydrotreatment feed and the obtained diesel boiling range fraction, and to widen the range of hydrocarbon types and molecular weights in the hydrotreatment feed and in the obtained diesel boiling range fraction, to compensate for the opposite effect of the renewable and/or circular content. Preferably, the cyclic hydrocarbons are predominantly naphthenes, so that diesel boiling range fractions with low aromatics content and hence better smoke point may be obtained. Too high aromatics content might also consume the hydrotreatment capacity jeopardising e.g. heteroatom removal efficiency.

In certain preferred embodiments, the petroleum feed has a total content of aromatics (EN 12916:2019+A1 :2022) within a range from 5 to 50 wt.-%, preferably from 8 to 45 wt.-%, more preferably from 10 to 40 wt.-%, based on the total weight of the petroleum feed. These embodiments reflect the advantageous heaviness of the petroleum feed, hence further contributing to the related benefits. Compared to using petroleum feeds having lower aromatics content, the present process is able to provide a diesel boiling range fraction in step c) having better cloud point, and additionally the availability of this kind of petroleum feeds is better, as well as the process economics. Some aromatics content in the petroleum feed may be beneficial so as to increase the density and energy content of the hydrotreatment feed and the obtained diesel boiling range fraction, and to widen the range of hydrocarbon types and molecular weights in the hydrotreatment feed and in the obtained diesel boiling range fraction, thereby compensating the opposite effect of the renewable and/or circular content. However, too high aromatics content would also mean higher polyaromatics content in the product, limited by diesel specifications as laid down e.g. in EN 590:2022, and have higher hydrogen consumption, thereby potentially compromising the hydrotreatment efficiency, including heteroatom removal. This is not desired as especially compromised deoxygenation efficiency would lead to lower oxidation stability of the products, e.g. residual triglycerides might remain as heavy tail, and also certain applications may have upper limit for oxygen-content of hydrocarbon products. In certain preferred embodiments, the petroleum feed has a density at 15°C (EN ISO 12185- 1996) within a range from 840 to 890 kg/m3, preferably from 845 to 880 kg/m3, more preferably from 850 to 880 kg/m3. These embodiments reflect the advantageous heaviness of the petroleum feed, hence further contributing to the related benefits. The density of the petroleum feed is contributed by its content of cyclic hydrocarbons, these increasing both the density and energy content of the hydrotreatment feed and the obtained diesel boiling range fraction, thereby compensating for the opposite effect of the renewable and/or circular content. As the petroleum feed as such is too heavy e.g. for use in diesel fuels, coprocessing it with the renewable and/or circular feed may be seen as a way of upgrading it to diesel boiling range.

In certain preferred embodiments, the hydrotreatment feed has a total content of sulphur (ASTM D7039-15a(2020)) within a range from 0.01 wt.-% to 3.0 wt.-%, preferably from 0.05 wt.-% to 2.0 wt.-%, more preferably from 0.1 wt.-% to 1 .5 wt.-%, based on the total weight of the hydrotreatment feed. Petroleum feeds are known to have significant sulphur contents. By incorporating in the hydrotreatment feed a high share of petroleum feed, the hydrotreatment catalyst may remain sufficiently sulphided and hence active even without separate sulphur spiking. Additionally, when the sulphur content of the hydrotreatment feed is somewhat elevated, such as at least 0.05 wt.-%, or more typically at least 0.1 wt.-%, based on the total weight of the hydrotreatment feed, deoxygenation via decarb-reactions may get more and more favoured over hydrodeoxygenation. If deoxygenation would proceed only via HDO route, particularly vegetable oil(s), animal fat(s), and/or microbial oil(s) that are rich in C18 and C16 fatty acids, would lead to high contents of C18 and C16 n-paraffins having poor cold properties. Hence, particularly for these renewable feeds, deoxygenation partially via decarb route is seen as beneficial for the cold properties and cold flow additive response, so as to avoid any individual carbon number, and particularly any n-paraffin, to become dominant in the diesel boiling range fraction recovered in step c).

In certain embodiments, the hydrotreatment feed has a total content of nitrogen (ASTMD5762-18a) at most 5000 wt-ppm, preferably at most 2000 wt-ppm, more preferably at most 1000 wt-ppm, based on the total weight of the hydrotreatment feed. In these embodiments sufficient HDN and deoxygenation efficiency may be achieved, and temperature in the hydrotreatment reactor remains within reasonable limits, in turn helping to control cracking and decarb-reactions. Additionally, too high nitrogen content might compromise deoxygenation efficiency, which is not desired as leading to lower oxidation stability of the products, etc as discussed in the foregoing. This said, in the present process there is room for somewhat elevated nitrogen content in the hydrotreatment feed, due to the limited content of the renewable and/or circular feed and also as the oxygenated hydrocarbon species abundant in these feeds are relatively easy to deoxygenate. Consequently, a more relaxed pretreatment protocol in view of nitrogen may be utilised for the renewable and/or circular feed.

In certain preferred embodiments, the petroleum feed comprises straight-run distillate(s) of crude oil in a total amount of at least 80 wt.-%, preferably at least 85 wt.-%, more preferably at least 90 wt.-%, based on the total weight of the petroleum feed, or the petroleum feed may consist essentially of straight-run distillate(s) of crude oil. These embodiments are advantageous as crude oil distillation process is a convenient means to adjust the distillation properties of the petroleum feed as desired for the present process. Furthermore straight- run distillates of crude oil have typically negligible olefin contents e.g. compared to crude oil based (hydro)crackates, which is beneficial in view of the hydrotreatment capacity and temperature control, that are important when co-processing sustainable feeds. Straight-run distillates of crude oil have typically also higher paraffin contents compared to crude oil based (hydro)crackates, and better cetanes but poorer cold properties. When co-processing sustainable feeds with straight-run distillate(s) as the major component, the petroleum feed may also contain middle distillate fraction(s) of (hydro)crackate(s) to provide balance: the sustainable content may help to compensate the cetane-decreasing effect of the (hydro)crackates, straight-run distillate(s) as the major petroleum feed component may help to compensate the higher hydrotreatment capacity consumption of the (hydro)crackates and sustainable feeds, and the (hydro)crackates may help to compensate the poorer coldproperties of the straight-run distillate(s) and sustainable content. Hence in certain preferred embodiments, the petroleum feed comprises straight-run distillate(s) of crude oil and crude oil based (hydro)crackates, and the weight-ratio of the straight-run d istil late(s) of crude oil to the crude oil based (hydro)crackates is within a range from 80:20 to 98:2, preferably from 85:15 to 98:2, more preferably from 90:10 to 95:5.

In the present process renewable and/or circular content is incorporated in the hydrotreatment feed. This is foreseen to increase n-paraffin content in the product fractions as upon hydrotreatment e.g. typical fatty materials and liquefied waste plastics become rich in paraffins whereof well over 50 wt.-% may be n-paraffins, that are excellent cetane enhancers.

Examples of renewable and/or circular feeds include vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s) and/or liquefied organic waste, whereof vegetable oil(s), animal fat(s), microbial oil(s), and lignocellulose-derived biocrude(s) are essentially biogenic, and liquefied organic waste typically has both biogenic and non- biogenic content. Typical vegetable oil(s), animal fat(s), microbial oil(s), lignocellulosederived biocrude(s), and/or liquefied organic waste may contain for example fatty acid(s), fatty acid glyceride(s), fatty acid alkyl ester(s), fatty alcohol(s), resin acid(s), resin ester(s), other oxygenated hydrocarbons, olefins, and/or cyclic hydrocarbons.

Exemplary vegetable oil(s) usable in the present process include rapeseed oil, canola oil, soybean oil, coconut oil, sunflower oil, palm oil, palm kernel oil, peanut oil, linseed oil, sesame oil, maize oil, poppy seed oil, cottonseed oil, soy oil, tall oil, crude tall oil (CTO), corn oil, castor oil, jatropha oil, jojoba oil, olive oil, flaxseed oil, camelina oil, safflower oil, babassu oil, seed oil of any of Brassica species or subspecies, such as Brassica carinata seed oil, Brassica juncea seed oil, Brassica oleracea seed oil, Brassica nigra seed oil, Brassica napus seed oil, Brassica rapa seed oil, Brassica hirta seed oil and Brassica alba seed oil, and rice bran oil, and/or fractions or residues of said vegetable oils such as palm olein, palm stearin, palm fatty acid distillate (PFAD), purified tall oil, tall oil fatty acids, tall oil resin acids, distilled tall oil, tall oil unsaponifiables, tall oil pitch (TOP), and/or used cooking oils of vegetable origin; exemplary animal fats may include tallow, lard, yellow grease, brown grease, fish fat, poultry fat, and/or used cooking oil of animal origin; and exemplary microbial oils may include algal lipids, fungal lipids, and/or bacterial lipids. The lignocellulose-derived biocrude(s) may comprise thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied lignocellulosics, wherein exemplary lignocellulosics may include woody biomass and residues such as wood chips, sawdust, forestry thinnings, road cuttings, bark, branches, garden and park wastes and weeds, energy crops like coppice, willow, miscanthus, and giant reed; agricultural (by)products such as grasses, straw, stems, stover, husk, cobs and shells from e.g. wheat, rye, corn rice and/or sunflowers, empty fruit bunches from palm oil production, palm oil manufacturers effluent, residues from sugar production such as bagasse, vinasses, molasses and/or greenhouse wastes, energy crops like miscanthus, switchgrass, sorghum, and/or jatropha; and/or lignocellulosic industrial waste streams such as paper sludges, off- specification fibres from paper production, residues and byproducts from food production such as juice or wine production, vegetable oil production, restaurant wastes.

The liquefied organic waste may comprise thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied organic waste, wherein the organic waste may comprise waste plastics, end of life tires (ELT), 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.

If the vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and/or liquefied organic waste contain amounts or species of impurities that are not tolerated or preferred in the hydrotreatment, the content of said impurities may be reduced to acceptable limits using pretreatment methods known in the art. Exemplary pretreatment methods suitable for the present disclosure comprise treating with mineral acids, degumming, treating with hydrogen, heat treating, deodorizing, washing with water, treating with base, demetallation, distillation, removal of solids, bleaching, and any combinations thereof.

In certain preferred embodiments, the renewable and/or circular feed is selected from vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), liquefied organic waste, and combinations thereof, these providing efficient reduction of GHG emissions and carbon footprint, and being good source of diesel boiling range hydrocarbons upon hydrotreatment. In certain further preferred embodiments, the renewable and/or circular feed is selected from vegetable oil(s), animal fat(s), microbial oil(s), and combinations thereof. These are fully biogenic, and become rich in n-paraffins upon hydrotreatment, thereby enhancing cetane of the obtained diesel boiling range fraction. Additionally, renewable propane is formed from the glycerol backbone typically present in these lipidic materials. The formed propane may be separated from the hydrotreatment effluent and/or from the separation stage and utilised e.g. as purified for production of renewable propylene, or among other light hydrocarbons for production of renewable hydrogen in a hydrogen production unit.

In certain preferred embodiments the renewable and/or circular feed has a total content of glycerides of at least 75 wt-%, preferably at least 80 wt-%, more preferably at least 85 wt- %, even more preferably at least 90 wt-%, further preferably at least 95 wt-%, based on the total weight of the renewable and/or circular feed. Glycerides, or acylglycerols, are esters formed from glycerol and fatty acids. As used herein, by glycerides it is meant mono-, di- or triglycerides, or any combinations thereof. By using a highly glyceridic renewable feed instead of a feed rich in free fatty acids, it is possible to further reduce corrosion risk, particularly when using a hydrotreatment unit of an existing petroleum refinery. This is because presence of free fatty (or resin) acids may increase the total acid number (TAN) of the renewable and/or circular feed to a level that the corrosion resistance e.g. of an existing refinery hydrotreatment unit is not designed for, hence involving increased corrosion risk, and risk of corrosion products entraining in the hydrotreatment catalyst beds and plugging them. Furthermore, as the glycerol moiety forms propane upon hydrotreatment, it may be seen as diluting CO content in the gaseous stream, thereby mitigating CO-related corrosion risk in the gas management of an existing refinery. In certain preferred embodiments the renewable and/or circular feed has a total content of free fatty fatty acids and/or free resin acids of at most 20 wt-%, preferably at most 15 wt-%, more preferably at most 10 wt-%, even more preferably at most 5 wt-%, based on the total weight of the renewable and/or circular feed. The content of the free fatty and/or resin acids may be reduced by any methods known in the field.

In certain preferred embodiments the renewable and/or circular feed has a total content of waste and/or residue fats of at least 70 wt-%, preferably at least 80 wt-%, more preferably at least 90 wt-%, even more preferably at least 95 wt-%, based on the total weight of the renewable and/or circular feed. Typical fats originating from waste and/or residues include used cooking oil, used restaurant fats, slaughterhouse residues, brown grease e.g. from fat traps and sewage, yellow grease, white grease, palm effluent sludge, acid oils, acidulated soapstock, technical corn oil, empty fruit bunch oil, used lubricating oils, just to name a few. Even such very low-quality materials may be utilised in the present process, as facilitated by the limited content of the renewable and/or circular feed in the hydrotreatment feed.

In certain particularly preferred embodiments the renewable and/or circular feed comprises animal fat. Animal fats are known to have elevated content of nitrogen impurities, for example compared to many food grade vegetable oils. Due to the limited content of the renewable and/or circular feed in the hydrotreatment feed, and since the oxygenated hydrocarbon species present in these are relatively easy to deoxygenate, there is room for somewhat elevated nitrogen content in the hydrotreatment feed. The animal fat does not require extensive purification for incorporation into the hydrotreatment feed, but e.g. a conventional bleaching protocol may suffice. The renewable and/or circular feed may have a total animal fat content varying in broad ranges, such as at least 1 wt.-%, preferably at least 10 wt.-%, more preferably at least 25 wt.-%, based on the total weight of the renewable and/or circular feed, or the renewable and/or circular feed may even consist thereof. The present process provides synergism in terms of combined removal of covalently bound nitrogen, sulphur and oxygen, and of olefinic unsaturations and aromatics, all attainable even in a single stage hydrotreatment. Additionally animal fats have an elevated content of C16 fatty acids, commonly within 20-30 wt.-% range, that is beneficial for providing even better synergy regarding the cold properties, particularly the cloud point of the diesel boiling range fraction recovered in step c). Furthermore, animal fat has limited content of unsaturates, and particularly of polyunsaturates, so that the risk of challenges as discussed in the following, such as recombination reactions with sulphur-containing species, are not increased. Also other side reactions may be limited, even at elevated hydrotreatment temperatures.

In certain preferred embodiments the renewable and/or circular feed has a total content of C16 fatty acids (calculated as free fatty acid) of at least 15 wt.-%, preferably at least 20 wt.- %, more preferably at least 25 wt.-%, based on the total weight of the renewable and/or circular feed. Compared to renewable and/or circular feeds consisting essentially of C18 or longer fatty acids, these embodiments may provide even better synergy regarding the cold properties, particularly the cloud point of the diesel boiling range fraction recovered in step c).

In preferred embodiments the renewable and/or circular feed has an iodine number (ISO 3961-2018) less than 100 grams of iodine consumed by 100 g of the renewable and/or circular feed (g 1/100g), preferably less than 90 g 1/100g, more preferably less than 80 g 1/100g. By utilising renewable and/or circular feed having controlled amount of unsaturation, as reflected by the iodine number, several benefits may be attained in co-processing: reduced risk of recombination reactions of unsaturated species with sulphur-containing species during the hydrotreatment, the reaction products of which would end up in the diesel boiling range fraction recovered in step c); reduced risk of residual olefins ending up in the obtained diesel boiling range fraction harming stability, such as oxidation stability thereof; reduced overall and local hydrogen consumption in the hydrotreatment catalyst bed, so that formation of hydrogen-poor spots may be avoided; easier temperature control in the hydrotreatment reactor, as olefin saturation is highly exothermic and occurs in the beginning of the hydrotreatment catalyst bed causing sharp temperature increase therein. In particularly preferred embodiments, the renewable and/or circular feed has total polyunsaturates content less than 20 wt.-%, based on the total weight of the renewable and/or circular feed. The present process involves subjecting the hydrotreatment feed to hydrotreatment in a hydrotreatment reactor in the presence of a hydrotreatment catalyst to obtain a hydrotreatment effluent.

The hydrotreatment is conducted in the presence of added hydrogen. The hydrotreatment may be conducted e.g. using any hydrotreatment reactor(s), conditions and hydrotreatment catalyst(s) known by a skilled person and/or conventionally used e.g. in petroleum refineries. In certain preferred embodiments, the hydrotreatment in step b) is conducted at a temperature, as measured at the reactor inlet, within a range from 310 °C to 450 °C, preferably from 320 °C to 400 °C, a pressure within a range from 7 MPa to 20 MPa, preferably from 8 MPa to 15 MPa, a H2 partial pressure at the inlet of the hydrotreatment reactor within a range from 7 MPa to 20 MPa, preferably from 8 MPa to 15 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrotreatment feed per kg hydrotreatment 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, utilising elevated temperature at the reactor inlet allows higher hydrodeoxygenation reaction activity already in the beginning, releasing more capacity for HDS and HDN reactions towards the reactor outlet. The elevated temperature may also to some extent compensate for hydrotreatment catalyst deactivation during continued operation of the catalytic hydrotreatment. Additionally, the relatively high hydrogen pressure in the hydrotreatment helps to minimise presence and formation of olefins, thereby contributing i.a. to reduced recombination and other side reactions during the hydrotreatment, and improved stability of the product fractions. Moreover, the relatively high hydrogen pressure in the hydrotreatment helps to control or suppress cracking reactions, and also deoxygenation via decarbreactions, thereby balancing the decarb-enhancing influence of elevated sulphur content in the hydrotreatment feed. Additionally, as water-gas shift is an equilibrium reaction (CO + H2O «-> CO2 + H2) the relatively high hydrogen pressure helps to shift the equilibrium to CO-side, and furthermore, to hydrogenate most of the CO to methane. In this way both CO2 and CO contents may be reduced in the gaseous stream separated from the hydrotreatment effluent, and also in a recycle hydrogen stream that may be recovered from the gaseous stream. This is foreseen to reduce CO-related corrosion risk, and allows the recycle hydrogen stream to be recycled back in higher amounts e.g. to the present process or to refinery’s other hydrotreatment, hydroisomerisation and/or hydrocracking units. Additional CO-removal/treatment may be avoided, reducing process complexity. Lower CO2 and CO contents in the gaseous stream also reduces the risk of the existing, normal sweetening capacity of the refinery to become insufficient for treating the gaseous stream.

The hydrotreatment catalyst may be any conventionally used hydrotreatment catalyst or combination thereof, no special catalysts are needed. Exemplary hydrotreatment catalysts include those described in various handbooks in the field, such as in Handbook of Petroleum Processing, Springer 2006, edited by Jones and Pujado, Chapter s Hydrotreating, Catalysts p. 334-344; in Petroleum Refining, Vol 3 Conversion Processes, Editions Technip 2001 , edited by P. Leprince, Chapter 16 Hydrotreating p. 546-549; and in Handbook of Petroleum Refining, CRC Press 2017, edited by James G. Speight, Chapter 10 Hydrotreating processes p. 423-424; or in patent publications, especially in FI100248B, EP1741768A1 , EP2155838B1 or FI129220B1. Hence, in certain embodiments the hydrotreatment catalyst comprises at least one or more metals from Group VIII of the Periodic Table and/or from Group VI B of the Periodic Table, preferably at least one or more of Ni, Mo, W, and/or Co, even more preferably at least one or more of Ni and/or Co and Mo and/or W, such as NiMo, CoMo, NiCoMo, NiW, and/or NiMoW, preferably on a support such as alumina and/or silica, more preferably gamma-alumina, optionally additized with minor amounts of silica or phosphorous. These hydrotreatment catalysts are efficient, readily available, commonly used e.g. for HDS of petroleum feeds and are usable also for HDO of e.g. fatty feeds, and tolerate typical impurities of the hydrotreatment feed used in the present process well.

Also catalyst(s) containing acidic porous material(s), especially zeolite(s) and/or zeolitetype material(s), having suitable shape-selective framework type, and optionally also metal sites for catalysing (de)hydrogenation reactions, e.g. as described in Handbook of Petroleum Refining, CRC Press 2017, edited by James G. Speight, Chapter 12.3.5 Catalytic Dewaxing Process p. 548-550, may be utilised as hydrotreatment co-catalysts, at least in one catalyst bed in the hydrotreatment reactor, so as to reduce content of long n-paraffins and to increase content of isoparaffins and/or cracked paraffins in the hydrotreatment effluent. These catalysts are herein referred to as dewaxing catalysts. Hence, in certain preferred embodiments, in step b) the hydrotreatment 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. The hydrotreatment may be arranged in a single hydrotreatment stage or it may comprise multiple hydrotreatment stages arranged in multiple hydrotreatment zones in one or more hydrotreatment reactor(s), depending on practical issues and engineering preferences. In certain preferred embodiments the hydrotreatment is arranged in a single hydrotreatment stage, which is enough for obtaining a sufficiently hydrotreated, good quality diesel boiling range fraction as the separation stage bottom in step c). Typically hydrotreating reactors are downflow, fixed-bed reactors, generally operating in trickle flow regime.

In step c) of the present process the hydrotreatment effluent is introduced into a separation stage, and at least a diesel boiling range fraction is recovered as the separation stage bottom. In certain preferred embodiments, the separation stage in step c) comprises subjecting the hydrotreatment effluent to a gas-liquid separation to obtain a gaseous stream and a degassed hydrocarbon stream, and subjecting the degassed hydrocarbon stream to stabilisation and/or fractionation to recover at least a light naphtha fraction, and the diesel boiling range fraction as the separation stage bottom. In the separation, water that e.g. may form during the hydrotreatment in the course of hydrodeoxygenation of oxygenated hydrocarbons, is typically also separated and removed. Recovering the diesel boiling range fraction as the separation stage bottom provides high energy savings, and it may also provide a wider distillation tail, i.e. difference between FBP and T90, compared to a diesel recovered as a distillate, thereby enhancing the response to cold flow additives.

The separation stage of the present process may utilise any conventionally used separation and/or fractionation technology. The separation stage may be carried out in a separation stage system comprising one or more separation and/or fractionation units. For example, at least part of the gases 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. As used in the present disclosure, stabilisation refers to vapor pressure reduction to a flash point of more than 55°C in the diesel boiling range fraction. The fractionation may be conducted for example using e.g. a distillation column. The diesel boiling range fraction of step c) may be recovered as the separation stage bottom e.g. from a stabilisation unit or a fractionation unit downstream of the gas-liquid separation. As mentioned, in the separation stage the hydrotreatment effluent is preferably subjected at least to a gas-liquid separation. Similar considerations apply also to an effluent from the hydroisomerisation as described in the following. The gas-liquid separation of said effluent(s) may be conducted for example as an integral step within the respective reactor, or as a separate step. Typically, the gas-liquid separation is conducted at a temperature within a range from 0 °C to 500 °C, such as from 15°C to 300°C, or from 15 °C to 150 °C, preferably from 15 °C to 65 °C, such as from 20 °C to 60 °C, and preferably at essentially same pressure as that of the reactor where from the effluent originates. Typically, the pressure during the gas-liquid separation(s) may be within a range from 0.1 MPa to 20 MPa, preferably from 1 MPa to 18 MPa, or from 3 MPa to 15 MPa. The gas-liquid separation allows to separate compounds that are gaseous under the separation conditions (herein referred to as a gaseous stream) from the respective effluent.

Exemplary compounds retained in a gaseous stream separated from the hydrotreatment effluent may include at least one or more of residual hydrogen, hydrogen disulphide, ammonia, light hydrocarbons (C1-C4), carbon monoxide, and/or carbon dioxide. The presence and/or content of said compounds may vary. For example carbon monoxide and carbon dioxide are typically more abundant in a gaseous stream separated from the hydrotreatment effluent, while a gaseous stream separated from the effluent from an optional hydroisomerisation generally contains 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 a 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 recovered liquid fractions, 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 recovered liquid fractions. In certain preferred embodiments, a recycle hydrogen stream, fuel gases and/or a light naphtha fraction is/are further recovered from the separation stage, and at least a portion of the fuel gases and/or the 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) and/or to the hydroisomerisation in step d). This enhances the process economy. 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 diesel or aviation fuels. A diesel boiling range fraction recovered in step c) and/or step d) of 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. Also an aviation fuel range fraction obtainable by embodiments of the present process may meet several specification requirements as laid down in ASTM D1655-2023 Table 1 for an aviation fuel.

In certain preferred embodiments, a portion of the diesel boiling range fraction recovered in step c) is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive. The present inventors found that the present process enables production of a diesel boiling range fraction in step c) having better cold properties, particularly better cloud point, than expected e.g. in view of high melting points of n-paraffins in diesel boiling range, therefor increasing its value as a diesel fuel component. Also an improved response to conventional cold flow additive(s) may be achieved.

In certain preferred embodiments, the diesel boiling range fraction recovered in step c) has T5 temperature (EN ISO 3405-2019) within a range from 170°C to 270°C, preferably from 180°C to 260°C, more preferably from 190°C to 250°C.

In certain preferred embodiments, the diesel boiling range fraction recovered in step c) has a kinematic viscosity at 40 °C (EN ISO 3104-2020) within a range from 1.5 to 5.5 mm2/s, preferably from 1 .8 to 5.0 mm2/s, more preferably from 2.0 to 5.0 mm2/s. As facilitated by the renewable and/or circular content, the diesel boiling range fraction recovered in step c) of the present process may have a lower kinematic viscosity compared to a diesel boiling range fraction obtained by an otherwise similar process but using the petroleum feed alone.

In certain preferred embodiments, the diesel boiling range fraction recovered in step c) has a density at 15 °C (EN ISO 12185-1996) within a range from 820 to 850 kg/m3, preferably from 820 to 845 kg/m3, more preferably from 825 to 845 kg/m3. As facilitated by the renewable and/or circular content, the diesel boiling range fraction recovered in step c) of the present process may have a lower density compared to a diesel boiling range fraction obtained by an otherwise similar process but using the petroleum feed alone, but at the same time the heaviness of the used petroleum feed ensures sufficiently high density levels, so that the obtained diesel boiling range fraction can be incorporated into diesel fuels in higher blending ratios, or even without limitations, while meeting density specification e.g. as laid down in EN 590:2022 Table 1. In certain preferred embodiments, the diesel boiling range fraction recovered in step c) has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 170°C to 380°C, preferably within a range from 180°C to 370°C, more preferably from 190°C to 360°C, and a difference between T90 and T20 temperatures (EN ISO 3405-2019) at least 68°C, preferably at least 70°C, more preferably at least 72° C. In these embodiments the response of the diesel boiling range fraction recovered in step c) 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 embodiments also other diesel fuel additive(s) in addition to the cold flow additive(s) may be incorporated in the diesel fuel 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 fuel dye(s).

In certain preferred embodiments, the diesel boiling range fraction recovered in step c) has at least one or more of the following:

- a biogenic carbon content within a range from 1 to 40 wt.-%, based on the total weight of carbon (TC) in the diesel boiling range fraction (EN 16640:2017), preferably within a range from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-%; and/or

- a total content of n-paraffins within a range from 12 wt.-% to 60 wt.-%, preferably from 15 wt.-% to 55 wt.-%, more preferably from 20 wt.-% to 50 wt.-%.

All these characteristics of the diesel boiling range fraction recovered in step c) may be contributed at least to some extent by the properties specified in the foregoing for the petroleum feed, for the renewable and/or circular feed, for the hydrotreatment feed, for the hydrotreatment, and for the separation stage.

The present process comprises d) subjecting a hydroisomerisation feed comprising a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation in a hydroisomerisation reactor in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, and recovering from the hydroisomerisation effluent at least a second diesel boiling range fraction having a lower cloud point compared to the diesel boiling range fraction recovered in step c). Subjecting only a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation is particularly beneficial, as allowing flexible production of different product grades with limited hydroisomerisation capacity. This is desired, as conventional oil refineries have typically far less of hydroisomerisation capacity than hydrotreatment/cracking capacity. In certain particularly preferred embodiments, at least 10 wt.-%, preferably at least 20 wt.-%, more preferably at least 30 wt.-%, and at most 80 wt.-%, preferably at most 60 wt.-%, more preferably at most 50 wt.-%, of the diesel boiling range fraction recovered in step c) is subjected to hydroisomerisation.

In certain embodiments, the second diesel boiling range fraction has at least 5 °C, preferably at least 10 °C, more preferably at least 15 °C, even more preferably at least 25 °C lower cloud point (ISO 3015-2019) compared to the diesel boiling range fraction recovered in step c), and advantageously at least a portion of the second diesel boiling range fraction recovered in step d) is blended with a portion of the diesel boiling range fraction recovered in step c). The limited hydroisomerisation capacity may be utilised to provide a middle distillate of over quality in terms of cold properties, and to blend such middle distillate with at least a portion of the remaining diesel boiling point fraction recovered in step c) to provide a diesel fuel or component having desired cold properties. Hydroisomerising to over quality may also help in optimising or balancing the streams of the hydrotreatment and hydroisomerisation reactors having different capacities. Finally, as middle distillate(s) having the desired cold properties may be provided by subjecting only a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation, and without subjecting to hydrocracking, significant yield benefits are achieved. E.g. hydroisomerisation may reduce middle distillate(s) yield by about 2%, and hydrocracking significantly more.

In certain preferred embodiments, step d) comprises recovering from the hydroisomerisation effluent an aviation fuel range fraction as a distillate, and preferably the second diesel fuel range fraction as a distillation bottom. In certain further preferred embodiments at least a portion of the second diesel boiling range fraction recovered in step d) is introduced into a cold climate diesel fuel range pool. These embodiments facilitate simultaneous production of diesel fuel range pools for at least two different diesel fuel grades, or simultaneous production of at least a component for temperate climate diesel fuels and a component for aviation fuels.

The hydroisomerisation is conducted in the presence of added hydrogen. The hydroisomerisation may be conducted e.g. using any hydroisomerisation reactor(s), conditions and catalyst(s) known by a skilled person and/or conventionally used e.g. in petroleum refineries or in HVO plants.

The hydroisomerisation in the hydroisomerisation reactor may for example be conducted at a temperature, as measured at the reactor inlet, 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 MPa to 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 hydroisomerisation 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. For example, one of the hydroisomerisation catalysts loaded in the hydroisomerisation reactor may be highly selective for isomerisation reactions and another hydroisomerisation catalyst loaded in the hydroisomerisation reactor 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 FI100248B, EP1741768A1 , EP1741768A1 , EP2155838B1 , FI129220B1 , EP1396531A2, or EP0985010A1. Hence, in certain embodiments the hydroisomerisation catalyst is a bifunctional hydroisomerisation catalyst, preferably a non-sulphided bifunctional hydroisomerisation catalyst, comprising at least one or more metals selected from Group VIII of the Periodic Table, preferably from Ni, Pt and/or Pd; and at least one or more acidic porous materials selected from zeolites and/or zeolite-type materials, wherein preferably at least one or more of the zeolites and/or zeolitetype 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- 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.

In step d), recovering the second diesel boiling range fraction from the hydroisomerisation effluent may involve mere gas-liquid separation, and optionally stabilisation, thereby reducing the investment and operating costs, and maximising yield of the recovered fraction.

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 monobranched 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 equal severity conditions for the majority of the feed molecules.

The obtained second diesel boiling range fraction and optionally recovered aviation fuel range fraction may have high isoparaffin content, generally at least 85 wt.-%, preferably at least 90 wt.-%, more preferably at least 95 wt.-%, based on the total weight of paraffins in the fraction, and a high multiple-branched isoparaffin content, generally at least 50 wt.-%, preferably at least 55 wt.-%, more preferably at least 60 wt.-%, based on the total weight of paraffins in the fraction. High isomerisation degree contributes to good cold properties such as lower freezing point, lower kinematic viscosity at -20 °C, and lower cloud point, without a need to reduce the final boiling point of the fraction. Gas-liquid separation and optionally stabilisation may be sufficient to recover a second diesel boiling range fraction suitable for use in cold climate diesel fuels. Upon isomerisation, also fluidity, pumping and mixing characteristics and blendability of the fraction may improve, these being 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.

There may be further steps included either combined with the hydrotreatment and/or hydroisomerization steps, or thereafter. These may include e.g. hydropolishing, dearomatizing, distillation to remove heavy end of the diesel boiling range fraction, just to name a few. Typically, such additional process steps eventually aim at better control of desired properties of the recovered product fractions.

In certain embodiments, at least a portion of the light naphtha fraction optionally recovered in step c) is introduced into a gasoline fuel range pool, or used as a steam cracker co-feed, or co-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. While a vast majority of the hydrotreatment feed content, including the renewable and/or circular content, ends-up in the diesel boiling range fraction, some of it may crack and hence end-up in the naphtha range and fuel gases. However, due to the relatively well defined composition and properties of the petroleum feed, as well as its high share in the hydrotreatment feed, and as contributed by the hydrotreatment conditions disclosed in the foregoing, only very low amounts of the light naphtha fraction is formed. Therefore the most value-adding utilisation thereof may be as a co-feed to another process step, or as a supplementary component in a gasoline fuel range pool, instead of seeking dedicated uses for it. Most preferably, the recovered light naphtha fraction is co-fed to the hydrogen production unit so as to produce make-up hydrogen stream to be utilised in the hydrotreatment of step b) and/or in the hydroisomerisation of step d), thereby improving process economy.

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. Hence, in certain preferred embodiments, the hydrotreatment reactor in step b) and the hydroisomerisation reactor in step d), and optionally the hydrotreatment catalyst in step b) and/or the hydroisomerisation catalyst in step d), are as originally configured to treat a petroleum feed. For example a conventional refinery HDS unit may be used essentially without any changes thereto in step b). 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.

The recovered diesel boiling range fraction(s) 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 metalworking fluids, in rolling oils especially for aluminium, in cutting oils, in drilling fluids, in solvents, in lubricants, in extender oils, in carriers, in dispersant compositions, in demulsifiers, in extractants, in paint compositions, in coating fluids or pastes, in adhesives, in resins, in varnishes, in printing pastes or inks, in detergents, in cleaners, in plasticizing oils, in turbine oils, in hydrophobization compositions, in agriculture, in crop protection fluids, in construction, in concrete demoulding formulations, in electronics, in medical appliances, in compositions for car, electrical, textile, packaging, paper, cosmetic and/or pharmaceutical industry, and/or in manufacture of intermediates therefor. The elevated renewable and/or circular content, especially biogenic carbon content, in the recovered diesel boiling range fraction(s) adds value in all these applications.

Schematic presentation of the process

Fig. 1 schematically shows a process according to an example embodiment. A sustainable feed S, such as vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), and/or liquefied organic waste, optionally as pretreated in a pretreatment unit 100, is introduced into a hydrotreatment reactor 200 together with a petroleum feed P, forming a hydrotreatment feed 10. In the hydrotreatment reactor 200 the hydrotreatment feed 10 is subjected to hydrotreatment in the presence of a hydrotreatment catalyst to obtain a hydrotreatment effluent 20 whereof at least a portion is introduced into a separation stage 300. From the separation stage 300 at least a diesel boiling range fraction 30 is recovered as a separation stage bottom, and optionally also a gaseous stream 40 and a light naphtha fraction 50. At least a portion of the diesel boiling range fraction 30 may be incorporated into a temperate climate diesel fuel range pool 500, optionally at least with a cold flow additive 90. Fig. 1 also shows a hydroisomerisation step d), wherein a hydroisomerisation feed 60 comprising a portion of the diesel boiling range fraction 30 is subjected to hydroisomerisation in a hydroisomerisation reactor 400 in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, wherefrom at least a second diesel boiling range fraction 70 and optionally an aviation fuel range fraction 80 may be recovered.

EXAMPLES Example 1. Hydrotreatment of fully petroleum-based hydrotreatment feeds and hydrotreatment feeds having petroleum content as well as renewable and/or circular content

Animal fat was pretreated in a conventional manner by heat-treatment and bleaching to provide purified animal fat (AF) as the renewable and/or circular (sustainable) feed S1. Certain properties of S1 were analysed and are reported in Table 1. Two different petroleum feeds (P1 and P2) were provided by distilling a slightly lighter (P1 ) and a slightly heavier (P2) cut of a crude oil slate. Certain properties of P1 and P2 were analysed and are reported in Table 1 .

Table 1 . Brief description of the hydrotreatment feeds or components thereof.

Test runs were conducted with six different hydrotreatment feeds: P1 alone and blended with 5 wt.-% and 15 wt.-% of S1 as well as P2 alone as comparison feeds, and P2 blended with 5 wt.-% and 15 wt.-% of S1 according to the present disclosure. These feeds were hydrotreated in a hydrotreatment reactor using conventional hydrotreatment catalyst(s) (sulphided NiMo on alumina and NiMoW) and the following conditions: absolute pressure about 9 MPa, temperature about 340-370 °C, hydrogen to hydrotreatment feed ratio 500 normal liters H2 per liter hydrotreatment feed, and WHSV about 1.3 h“¹. From each hydrotreatment effluent a gaseous stream containing gases and some low-boiling hydrocarbons was removed to obtain a degassed hydrocarbon stream, that was stabilised to provide the diesel boiling range fraction as the separation stage bottom. Certain characteristics of the obtained diesel boiling range fractions were analysed, and are reported in Table 2.

Table 2. Certain characteristics of two diesel boiling range fractions obtained by the present process, and of four comparative diesel boiling range fractions: one obtained by an otherwise similar process but using the same petroleum feed P2 alone without S1 , two obtained using a lighter petroleum feed P1 with same amounts of S1 , and one obtained using the lighter petroleum feed P1 alone without S1 , in the hydrotreatment feed. Also certain diesel fuel specification requirements laid down in EN 590:2022 are presented. Contents of n-paraffins (nP), isoparaffins (iP), and naphthenes (N) were determined by GCxGC-FID/GCxGC-MS. EN590:2022 Table 3 refers to climate related requirements for arctic and severe winter climate diesels.

From Table 2 it can be seen that compared to hydrotreating the corresponding petroleum feed alone, co-feeding purified AF increased the n-paraffin content in the obtained diesel boiling range fractions, but not the isoparaffin content, which was slightly reduced. Also the content of sulphur and naphthenes decreased, while aromatics content remained approximately the same. Regarding physico-chemical properties it can be seen that compared to hydrotreating the corresponding petroleum feed alone, co-feeding purified AF improved (increased) the cetane. Hence, less or no cetane improver may be required to meet e.g. the cetane specification requirement as laid down in EN 590:2022. Surprisingly, in these tests also an improved copper corrosion class was observed when co-feeding purified AF, compared to the reference. However, the underlying phenomenon is not fully understood. Additionally, the density remained approximately the same, cloud point deteriorated (increased) significantly, and kinematic viscosity decreased slightly, when using the lighter petroleum feed P1. However, when using P2 as the petroleum feed, density and kinematic viscosity were decreased, which is beneficial in view of using the obtained diesel boiling range fractions as components in diesel fuels meeting EN590:2022 specifications. Also the cloud point remaining about the same may be regarded as surprising, as hydrotreated fats are highly n-paraffinic, having a cloud point of about +20°C, so increasing n-paraffin content in a hydrocarbon composition is generally expected to deteriorate cold properties.

Example 2. Alternative renewable and/or circular feeds

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

Table 3. Certain characteristics of a hydrotreated renewable feed R1 and a 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.

The data in Table 3 generally illustrates the contribution of the renewable and circular molecules to the diesel boiling range fractions obtainable by the present process if conventionally purified glyceridic feed of animal fat/vegetable oil origin and/or the conventionally purified liquefied waste plastic obtained by thermal degradation/pyrolysis of polyolefinic waste plastics were introduced directly into the hydrotreatment feed of the present process. From Table 3 it can be seen that after subjecting the renewable and circular feeds to hydrotreatment, the obtained hydrocarbon streams boil in the middle distillate range, and have high n-paraffin contents, over 60% of the total paraffin content. Incorporating such renewable and/or circular feeds into a hydrotreatment feed for producing diesel boiling range fractions might hence be expected to increase the n-paraffin content of the diesel boiling range fraction, and to deteriorate its cold properties, even significantly at higher incorporation amounts. This could then limit the blending ratio of the thus-obtained diesel boiling range fractions in diesel fuels, or even prevent their use in certain end-uses. However, as shown in Example 1 , especially Table 2, this is not the case when cohydrotreating the renewable and/or circular feed such as R1 and/or C1 with a suitably selected petroleum feed as in the present process, evidencing decreased density and decreased kinematic viscosity, as well as essentially non-deteriorated cloud point, all of which are beneficial in view of using the obtained diesel boiling range fractions as components in diesel fuels meeting EN590:2022 specifications. At the same time the yield of the diesel boiling range fraction recovered from the hydrotreatment effluent is good, clearly higher compared to otherwise similar processes but involving hydroisomerisation of the whole diesel boiling range fraction recovered from the hydrotreatment effluent, as hydroisomerisation causes a loss of middle distillate range of about 2%, and significantly higher compared to processes involving hydrocracking causing much higher loss to lighter/gaseous products. Example 3. Further study on the effect of the petroleum feed properties, and on response of the diesel boiling range fractions to conventional cold flow additives

Same purified animal fat (AF) as in Example 1 was utilised as the renewable and/or circular (sustainable) feed S1 . Petroleum feeds P3, P4 and P5 were provided. P3 was similar to P1 and P4 similar to P2, except both were somewhat lighter. P5 was prepared by blending 67 wt.-% of P4 and 33 wt.-% of P3. Certain distillation characteristics of the P3, P4, and P5 are presented in Table 4.

Table 4. Brief description of the hydrotreatment feed.

Test runs were conducted as described in Example 1 , except that 5 wt.-% of S1 and 95 wt.- % of P3, P4 or P5 were co-fed to the hydrotreatment, and for comparison purposes P3 or

P4 alone. Certain characteristics of the obtained diesel boiling range fractions were analysed, and are reported in Table 5. The n-paraffin distributions of the obtained diesel boiling range fractions are reported in Fig 2.

Table 5. Certain characteristics of two diesel boiling range fractions obtained by the present process using 95 wt.-% P4 and 5 wt.-% S1 in the hydrotreatment feed, and of three comparative diesel boiling range fractions: one obtained by an otherwise similar process but using P4 alone without S1 , or a lighter petroleum feed P3 with same amount of S1 , or using P3 alone without S1. Contents of n-paraffins (nP) were determined by GCxGC- FID/GCxGC-MS.

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* calculated using corresponding values of diesel boiling range fractions obtained using P3 and P4 alone, based on same wt.-% amounts as P3 and P4 in P5

In addition to total content of paraffins, in this Example also contents of C18 n-paraffins and heavier paraffins were analysed, as well as how the n-paraffins were distributed over the recovered diesel boiling range fractions (Fig 2). Similarly as from Table 2 of Example 1 , also from Table 5 it can be seen that co-feeding purified AF with different petroleum feeds led to an increase in total n-paraffin content. Table 5 also shows that the increase in the n-paraffin content was especially high in C18 and heavier paraffins. Also similarly as Table 2 of Example 1 , Table 5 shows that when the purified AF was co-fed with the lighter petroleum feed P3, the cloud point of the recovered diesel boiling range fraction deteriorated significantly compared to the corresponding petroleum-based fraction, but when the purified AF was co-fed with the heavier petroleum feed P4 or with the 0.33:0.67 blend of P3 and P4, the cloud point of the recovered diesel boiling range fractions deteriorated less than expected, based on linear assumption.

Based on Fig 2 it seems that the n-paraffin distribution of the diesel boiling range fraction obtained using the lighter petroleum feed P3 with S1 was bimodal, while the n-paraffin distributions of the diesel boiling range fractions obtained using the heavier petroleum feed P4 with S1 , or blend of P3 and P4 with S1 , seem more unimodal compared to the first mentioned. Without wishing to be bound to any theory it is believed that when the n-paraffins are more evenly distributed in the diesel boiling range fraction, and particularly when a dominating n-paraffin peak of any single carbon atom is avoided, the cold property harming effect that n-paraffins typically involve is attenuated at least to some extent. From Fig 2 it can also be seen that in all fractions obtained using S1 containing feed, the contents of C16 and C15 n-paraffins, respectively containing C16 fatty acid as hydrodeoxygenated and decarboxylated/decarbonylated, as well as C18 and C17, respectively containing C18 fatty acid as hydrodeoxygenated and decarboxylated/ decarbonylated, are of similar magnitude, i.e. neither of these deoxygenation routes have dominated when using these hydrotreatment feeds and conditions. The absence of any dominating n-paraffin is believed to contribute beneficially to the observed cold property behaviour.

The response of the diesel boiling range fractions to two different conventional cold flow additives was studied by adding the same cold flow additive dosage (0, 300 and 700 wt- ppm of the cold flow additive) to each fraction. The results, i.e. CFPP as a function of cold flow additive dosage, are reported in Fig 3a for the diesel boiling range fractions obtained using the lighter petroleum feed P3 with and without S1 , in Fig 3b for the diesel boiling range fractions obtained using the heavier petroleum feed P4 with and without S1 , and in Fig 3c for the diesel boiling range fraction obtained using the blend of P3 and P4 with S1. From the results shown in Fig 3a it can be seen that neither of the tested cold flow additives gave a significant (>3 °C) CFPP improvement in the diesel boiling range fractions obtained using the lighter petroleum feed P3. More specifically, CFPP of the fraction based on the lighter petroleum feed P3 alone could be slightly improved (3 °C) with the cold flow additives, while no improvement was achieved for the fraction based on co-feeding S1 and P3. However, the results in Fig 3b show that both of the tested cold flow additives gave approximately 5 °C CFPP improvement in the diesel boiling range fractions obtained using the heavier petroleum feed P4. Even more remarkably, the diesel boiling range fraction obtained using the blend of P3 and P4 with S1 exhibited a surprising response to both cold flow additives, improving the CFPP even by 11 °C. Without wishing to be bound to a theory it is believed that the wider distribution of n-paraffins in the diesel boiling range fraction obtained using the blend of P3 and P4, as shown by Fig 2 (and Table 5), provides a further enhancement to the cold flow additive response.

Example 4. Further study on response of the diesel boiling range fractions to conventional cold flow additives

In this example it was studied how the characteristics of the petroleum feed, especially its distillation characteristics, influence the responsiveness of the obtained diesel boiling range fractions to conventional cold flow additives. This was illustrated by preparing blends of diesel boiling range fractions obtained using the lighter petroleum feed P3 (without S1 ) with diesel boiling range fractions obtained using the heavier petroleum feed P4 (without S1 ), with and without admixing 5 wt.-% of hydrotreated conventionally purified animal fats/vegetable oil, as represented by the hydrotreated R1 reported in Table 3.

After analysing certain characteristics of these blends, the responsiveness of the blends to one conventional cold flow additive was studied by adding the same cold flow additive dosage (0, 300 and 700 wt-ppm of the cold flow additive) to each fraction/blend, and measuring CFPP again. CFPP measured for the fraction/blend as neat was subtracted from the CFPP measured for the fraction/blend with the additive (ACFPP), and the difference compared to the ACFPP of the base case i.e. P4 100 was calculated as the CFPP improvement (relative to P4 100). The results are reported in Table 6.

Table 6. Certain characteristics of blends of diesel boiling range fractions obtained using the lighter petroleum feed P3 (without S1 ), with diesel boiling range fractions obtained using the heavier petroleum feed P4 (without S1 ), with and without 5 wt.-% of hydrotreated animal fats/vegetable oils.

Based on these results, by blending in diesel boiling range fraction obtained using the lighter petroleum feed P3, it was possible to achieve CFPP improvement of up to 4 °C greater than that of the diesel boiling range fraction obtained using the heavier petroleum feed P4 alone. By incorporating increasing shares of the diesel boiling range fraction obtained using the lighter petroleum feed P3, the distillation range T90-T20 widens from 60 °C to 88 °C, and also the distillation tail FBP-T90 widens slightly, from 15 to 18 °C, as shown in Table 6. Both of these changes are believed to provide a further enhancement to the cold flow additive response. Similar effect may be foreseen when utilising as the hydrotreatment feed in the present process a blend of a heavier petroleum feed (such as P4) as a major component, and a lighter petroleum feed such as P3 as a supplemental component. Boosting the cold flow additive response by modifying the petroleum feed properties may enable higher renewable and/or circular feed contents in the hydrotreatment feeds without compromising cold flow properties and/or responsiveness to cold flow improvers.

Example 5. Further study on the effect of isomerisation

In this example hydroisomerisation of diesel boiling range fractions similar to those obtained in Example 1 was studied.

Same purified animal fat (AF) as in Examples 1 and 3 was utilised, this time blended with rapeseed oil, that had been heat-treated and bleached in conventional manner, in a weight ratio of 75:25 as the renewable and/or circular (sustainable) feed S2. The sustainable feed S2 contained 97 wt.-% glycerides, 2.1 wt.-% free fatty acids, 11 .3 wt.-% total oxygen (ASTM D5622-2017), and 160 wt-ppm nitrogen (ASTM D5762-2018a), and had iodine number 71 g l/100g (ISO 3961-2018).

Petroleum feeds P6 and P7 were provided, whereof P6 was similar to P1 and P7 similar to P2 regarding boiling properties, and also otherwise: Petroleum feed P6 had density at 15°C 836 kg/m3 (EN ISO 12185-1996) and cloud point -33.5°C (ISO 3015-2019), and contained about 17 wt.-% n-paraffins, 20.0 wt.-% i-paraffins, 38 wt.-% naphthenes (ASTMD2425), 27 wt.-% total aromatics (19 wt.-% mono, 7.8wt.-% di, 0.3wt.-% >tri) (EN 12916), 0.15 wt.-% sulphur (ASTM D7039-15a(2020)), and <40 wt-ppm nitrogen (ASTM D4629-2017). Petroleum feed P7 had density at 15°C 869 kg/m3 (EN ISO 12185-1996) and cloud point -

I .7°C (ISO 3015-2019), and contained about 15 wt.-% n-paraffins, 19 wt.-% i-paraffins, 34 wt.-% naphthenes (ASTMD2425), 33.3 wt.-% total aromatics (19.9 wt.-% monoaromatics,

I I .9wt.-% di, 1.5wt.-% >tri) (EN 12916), 0.44 wt.-% sulphur (ASTM D7039-15a(2020)), and 220 wt-ppm nitrogen (ASTM D4629-2017)

First, test runs were conducted as described in Example 1 , except that 20 wt.-% of S2 and 80 wt.-% of P6 or P7 were co-fed to the hydrotreatment, and for comparison purposes P7 alone. Certain characteristics of the obtained diesel boiling range fractions were analysed, and are reported in Table 7.

Table 7. Certain characteristics of diesel boiling range fraction DP7S2 obtained by the present process using 80 wt.-% P7 and 20 wt.-% S2 in the hydrotreatment feed, and of two comparative diesel boiling range fractions: DP7 obtained by an otherwise similar process but using P7 alone without S2, or a lighter petroleum feed P6 with same amount of S2 (DP6S2). Contents of n-paraffins (nP) were determined by GCxGC-FID/GCxGC-MS.

From Table 7 similar effects as observed in Example 1 , Table 2, can be seen when comparing DP7S2 (with co-fed S2) to DP7 (corresponding petroleum feed alone): Cofeeding S2 increased the n-paraffin content in the obtained diesel boiling range fractions, but not the isoparaffin content, which was slightly reduced. The content of naphthenes decreased significantly, while aromatics content reduced slightly. Cetanes were improved, and density and kinematic viscosity decreased, which is beneficial as noted in Example 1 , and surprisingly also the cloud point remained about the same, similarly as noted in Example 1 .

Next, a portion of DP7S2, as well as of DP6S2 and DP7 for comparison purposes, were subjected to hydroisomerisation (HI) using conventional noble metal hydroisomerisation catalyst, and lower severity conditions targeting summer quality diesel having cloud point of about 5°C, or higher severity conditions targeting winter quality diesel having cloud point of about -30°C. The lower severity hydroisomerisation conditions were 90 bar, 340°C and WHSV 1.3 1/h, and the higher severity hydroisomerisation conditions were 90 bar, 360°C and WHSV 1.3 1/h. From each hydroisomerisation effluent a gaseous stream containing gases and some low-boiling hydrocarbons was removed to obtain a degassed hydroisomerised stream, that was stabilised to provide the (second) diesel boiling range fraction as the separation stage bottom. Certain characteristics of the obtained (second) diesel boiling range fractions were analysed, and are reported in Table 8.

Table 8. Certain characteristics of the hydroisomerised diesel boiling range fractions.

From Table 8 it can be seen that by subjecting the diesel fractions of Table 7 to hydroisomerisation of different severities, the cold properties and particularly cloud points could be improved flexibly from 0°C to -5°C or even -30°C or less. At the same time aromatic hydrocarbons were converted to naphthenes. This is beneficial as many uses of hydrocarbon compositions have upper limit requirements or recommendations regarding aromatics content. For example, specifications for environmentally classified Swedish diesel fuel (MK1 ), require the content of total aromatics to be at most 5.0 vol-% (SS 155116:2022). Incorporating renewable content did not hinder reaching the reduced cloud point and the aromatic content reduction during the hydroisomerisation. The elevated cetane values achieved by the renewable content remained essentially the same after the hydroisomerisation, providing the benefit of requiring less or no cetane improver to meet the cetane specification.

When the hydroisomerisation was conducted using higher severity, as targeting to cloud point of about -30°C, incorporation of renewable content led to increased yield of compounds boiling below 300°C i.e. in the aviation fuel boiling range (for DP7S2 60 vol% recovered at 300°C), compared to the otherwise similar petroleum reference (for DP7 50 vol% recovered at 296°C). This evidences the flexibility of the present process, as in addition to providing a first diesel boiling range fraction for temperate climate diesel fuels, also winter grade diesel component and even aviation fuel component can be produced by subjecting a portion of the first diesel boiling range fraction to hydroisomerisation, with improved yield of aviation fuel range fraction compared to an otherwise similar but fully petroleum based process.

Furthermore, compared to the isomerised diesel fraction obtained using the lighter petroleum feed (DP6S2), the isomerised diesel fraction obtained using the heavier petroleum feed (DP7S2) exhibited much higher density. The higher density of the isomerised diesel fraction allows to blend it in higher volumes into a diesel fuel without undercutting the density requirement of the final blend. Thanks to the higher density and energy density per volume, the isomerised diesel fraction obtained using the heavier petroleum feed (DP7S2) also allows higher mileage per fuel tank volume compared to the isomerised diesel fraction obtained using the lighter petroleum feed (DP6S2).

Various embodiments have been presented. It should be appreciated that in this document, words comprise, include and contain are each used as open-ended expressions with no intended exclusivity. The foregoing description has provided by way of non-limiting examples of particular implementations and embodiments of the invention a full and informative description of the best mode presently contemplated by the inventors for carrying out the invention. It is however clear to a person skilled in the art that the invention is not restricted to details of the embodiments presented in the foregoing, but that it can be implemented in other embodiments using equivalent means or in different combinations of embodiments without deviating from the characteristics of the invention.

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

Claims

1 . A process for producing a diesel boiling range fraction, the process comprising: a) combining from 60 to 99 wt.-%, preferably from 65 to 97 wt.-%, more preferably from 70 to 92 wt.-% of a petroleum feed, and from 1 to 40 wt.-%, preferably from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-% of a renewable and/or circular feed to obtain a hydrotreatment feed having petroleum content as well as renewable and/or circular content, wherein the petroleum feed has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 180°C to 420°C, a difference between T95 and T5 temperatures (EN ISO 3405- 2019) within a range from 70°C to 200°C, and preferably a T50 temperature (EN ISO 3405- 2019) within a range from 290°C to 350°C, 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 the hydrotreatment effluent into a separation stage, and recovering from the separation stage at least a diesel boiling range fraction as the separation stage bottom, and d) subjecting a hydroisomerisation feed comprising a portion of the diesel boiling range fraction recovered in step c) to hydroisomerisation in a hydroisomerisation reactor in the presence of a hydroisomerisation catalyst to obtain a hydroisomerisation effluent, and recovering from the hydroisomerisation effluent at least a second diesel boiling range fraction having a lower cloud point compared to the diesel boiling range fraction recovered in step c).

2. The process according to claim 1 , wherein the petroleum feed has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 200°C to 400°C, preferably from 220°C to 400°C, and a difference between T95 to T5 temperatures (EN ISO 3405-2019) within a range from 75°C to 190°C, preferably from 80°C to 180°C.

3. The process according to claim 1 or 2, wherein the petroleum feed has a T50 temperature (EN ISO 3405-2019) within a range from 290°C to 340°C, preferably from 300°C to 340°C; and/or a T95 temperature (EN ISO 3405-2019) within a range from 330°C to 400°C, preferably from 340°C to 390°C.

4. The process according to any one of the preceding claims, wherein the petroleum feed has a density at 15°C (EN ISO 12185-1996) within a range from 840 to 890 kg/m3, preferably from 845 to 880 kg/m3, more preferably from 850 to 880 kg/m3.

5. The process according to any one of the preceding claims, wherein the petroleum feed has a total content of cyclic hydrocarbons (GCxGC-FID/GCxGC-MS) within a range from 40 to 99 wt.-%, preferably from 50 to 95 wt.-%, more preferably from 55 to 90 wt.-%, based on the total weight of the petroleum feed; and/or a total content of aromatics (EN 12916:2019+A1 :2022) within a range from 5 to 50 wt.-%, preferably from 8 to 45 wt.-%, more preferably from 10 to 40 wt.-%, based on the total weight of the petroleum feed.

6. The process according to any one of the preceding claims, wherein the hydrotreatment feed has a total content of sulphur (ASTM D7039-15a(2020)) within a range from 0.01 wt.-% to 3.0 wt.-%, preferably from 0.05 wt.-% to 2.0 wt.-%, more preferably from 0.1 wt.-% to 1.5 wt.-%, based on the total weight of the hydrotreatment feed.

7. The process according to any one of the preceding claims, wherein the petroleum feed comprises straight-run distillate(s) of crude oil in a total amount of at least 80 wt.-%, preferably at least 85 wt.-%, more preferably at least 90 wt.-%, based on the total weight of the petroleum feed, or the petroleum feed consists essentially of straight-run d isti llate(s) of crude oil.

8. The process according to any one of the preceding claims, wherein the renewable and/or circular feed is selected from vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), liquefied organic waste, and combinations thereof, preferably from vegetable oil(s), animal fat(s), microbial oil(s), and combinations thereof.

9. The process according to any one of the preceding claims, wherein the renewable and/or circular feed has at least one or more of the following features:

- a total content of glycerides of at least 75 wt-%, preferably at least 80 wt-%, more preferably at least 90 wt-%, based on the total weight of the renewable and/or circular feed; and/or

- a total content of free fatty acids and/or free resin acids of at most 20 wt-%, preferably at most 10 wt-%, more preferably at most 5 wt-%, based on the total weight of the renewable and/or circular feed; and/or

- a total content of waste and/or residue fats of at least 70 wt-%, preferably at least 80 wt- %, more preferably at least 90 wt-%, based on the total weight of the renewable and/or circular feed; and/or - a total content of C16 fatty acids (calculated as free fatty acid) of at least 15 wt.-%, preferably at least 20 wt.-%, more preferably at least 25 wt.-%, based on the total weight of the renewable and/or circular feed; and/or

- a total animal fat content of at least 10 wt.-%, preferably at least 25 wt.-%, based on the total weight of the renewable and/or circular feed, or more preferably the renewable and/or circular feed consists essentially of animal fat; and/or

- an iodine number (ISO 3961-2018) less than 100 grams of iodine consumed by 100 g of the renewable and/or circular feed (g 1/100g), preferably less than 90 g 1/100g, more preferably less than 80 g 1/100g.

10. The process according to any one of the preceding claims, wherein the separation stage in step c) comprises subjecting the hydrotreatment effluent to a gas-liquid separation to obtain a gaseous stream and a degassed hydrocarbon stream, and subjecting the degassed hydrocarbon stream to stabilisation and/or fractionation to recover at least a light naphtha fraction, and the diesel boiling range fraction as the separation stage bottom.

11 . The process according to any one of the preceding claims, wherein a portion of the diesel boiling range fraction recovered in step c) is introduced into a temperate climate diesel fuel range pool, optionally at least with a cold flow additive.

12. The process according to any one of the preceding claims, wherein step d) comprises recovering from the hydroisomerisation effluent an aviation fuel range fraction as a distillate, and preferably the second diesel fuel range fraction as a distillation bottom.

13. The process according to any one of the preceding claims, wherein the diesel boiling range fraction recovered in step c) has a density at 15 °C (EN ISO 12185-1996) within a range from 820 to 850 kg/m3, preferably from 820 to 845 kg/m3, more preferably from 825 to 845 kg/m3.

14. The process according to any one of the preceding claims, wherein the diesel boiling range fraction recovered in step c) has T5 and T95 temperatures (EN ISO 3405-2019) within a range from 170°C to 380°C, preferably within a range from 180°C to 370°C, more preferably from 190°C to 360°C, and a difference between T90 and T20 temperatures (EN ISO 3405-2019) at least 68°C, preferably at least 70°C, more preferably at least 72°C.

15. The process according to any one of the preceding claims, wherein the diesel boiling range fraction recovered in step c) has at least one or more of the following: - a biogenic carbon content within a range from 1 to 40 wt.-%, based on the total weight of carbon (TC) in the diesel boiling range fraction (EN 16640:2017), preferably within a range from 3 to 35 wt.-%, more preferably from 8 to 30 wt.-%; and/or

- a T5 temperature (EN ISO 3405-2019) within a range from 170°C to 270°C, preferably from 180°C to 260°C, more preferably from 190°C to 250°C.

16. The process according to any one of the preceding claims, wherein the hydrotreatment in step b) is conducted at a temperature, as measured at the reactor inlet, within a range from 310 °C to 450 °C, preferably from 320 °C to 400 °C, a pressure within a range from 7 MPa to 20 MPa, preferably from 8 MPa to 15 MPa, a H2 partial pressure at the inlet of the hydrotreatment reactor within a range from 7 MPa to 20 MPa, preferably from 8 MPa to 15 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg hydrotreatment feed per kg hydrotreatment 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.

17. The process according to any one of the preceding claims, wherein the second diesel boiling range fraction has at least 5 °C, preferably at least 10 °C, more preferably at least 15 °C, even more preferably at least 25 °C lower cloud point (ISO 3015-2019), compared to the diesel boiling range fraction recovered in step c), and optionally at least a portion of the second diesel boiling range fraction recovered in step d) is blended with a portion of the diesel boiling range fraction recovered in step c).

18. The process according to any one of the preceding claims, wherein at least 10 wt.-%, preferably at least 20 wt.-%, more preferably at least 30 wt.-%, and at most 80 wt.-%, preferably at most 60 wt.-%, more preferably at most 50 wt.-%, of the diesel boiling range fraction recovered in step c) is subjected to hydroisomerisation in step d).

19. The process according to any one of the preceding claims, wherein a recycle hydrogen stream, fuel gases and/or a light naphtha fraction is/are further recovered from the separation stage, and at least a portion of the fuel gases and/or the 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) and/or to the hydroisomerisation in step d).