Process and system for producing hydrocarbons having biogenic carbon content, a sample treatment and analysis system and use thereof

Abstract

A process for producing hydrocarbons having biogenic carbon content and a sweetened gas stream is provided. In the process a refinery feed having biogenic carbon content, non- biogenic carbon content and sulphur content is refined in a conversion unit to obtain a conversion effluent, wherefrom at least a gaseous stream and optionally an unstabilised naphtha stream comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, and a degassed hydrocarbon stream are separated. The separated gaseous stream is subjected to a sweetening treatment, and optionally at least one or more distillate(s) and a separation bottom are further separated from the degassed hydrocarbon stream. The process further comprises collecting as a sample an aliquot of the gaseous stream or an aliquot of the unstabilised naphtha stream, subjecting the sample to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, subjecting the exhaust gas sample, preferably as dehydrated, to a SOx removal treatment, and subjecting at least a portion of the SOx depleted gas sample to a biogenic carbon content determination. The present process provides a convenient and safe way to conduct the mass balancing, and biogenic carbon content determination in an output stream, for individual conversion units of a refinery, as required e.g. for an ISCC PLUS certification.

Description

[0001] PROCESS AND SYSTEM FOR PRODUCING HYDROCARBONS HAVING BIOGENIC CARBON CONTENT, A SAMPLE TREATMENT AND ANALYSIS SYSTEM AND USE THEREOF

[0002] TECHNICAL FIELD

[0003] The present disclosure generally relates to a process and system for producing hydrocarbons having biogenic carbon content. The disclosure relates particularly, though not exclusively, to a process and system for producing hydrocarbons involving a convenient and safe way to determine biogenic carbon content in a conversion unit’s gaseous or gascontaining output stream comprising H2S, preferably in all output streams of a conversion unit of a refinery. Also a sample treatment and analysis system is disclosed, as well as its use in a process for producing hydrocarbons having biogenic carbon content.

[0004] BACKGROUND

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

[0006] There is an ongoing need to reduce greenhouse gas (GHG) emissions and / or carbon footprint in the transportation and petrochemical industry. At the same time the demand for hydrocarbons in these and other fields increases worldwide, and the crude oil reserves are vanishing. Accordingly, interest towards the use of sustainable materials in hydrocarbon production is growing.

[0007] Fully biobased alternatives for drop-in replacements of fossil hydrocarbon products have been successfully created. For example Neste MY Renewable Diesel is a Hydrotreated Vegetable Oil (HVO) developed by Neste Corporation. It is made by NEXBTL™ process, which is a proprietary HVO process of Neste Corporation, from 100% renewable raw materials such as waste and residues, and results in as much as 75-95% less greenhouse gas (GHG) emissions over the fuel’s life cycle when compared with fossil diesel. Renewable Neste RE™, on the other hand, is a 100% renewable feedstock of Neste Corporation showing a GHG emission reduction of more than 85% over the life cycle when used to replace conventional fossil feedstock in the chemical and polymers industry.

[0008] In addition to concepts dedicated for processing fully biogenic feeds, for tackling the above- mentioned challenges further approaches for industrial processes and products are urgently needed. In this regard, co-feeding of biomass-derived streams into existing petroleum refineries has a growing interest not least because of the existing infrastructure, allowing almost instant implementation. When co-processing biogenic feedstocks with fossil feedstocks, the biogenic carbon content distributes unequally between the various output / product streams and hence different approaches have been developed to calculate the amount of the bio-output. For example, the International Sustainability and Carbon Certification (ISCC) has established a co-processing certification providing three different approaches for calculating the bio-yield: energetic determination; determination through the efficiency / losses of a process; and 12C / 14C analyses. For all three approaches, the determined sustainable bio-output can then be attributed to the respective products. 12C / 14C analysis is also one of four options offered by ISCC’s certification scheme ISCC PLUS for conducting the mass balancing for a certified processing unit and for determining the sustainable output.

[0009] WO2021100004A1 discloses a method to determine renewable carbon content while coprocessing biogenic feedstocks in a refinery environment during the production of renewable fuels. The proposed approach involves analyzing samples of liquid feedstocks and products collected from fixed sampling points of a petroleum coprocessing operation with a triple to double coincidence ratio (TDCR) scintillation counter. The proposed approach is said to reduce the total number of downstream measurements typically required when determining bio-based carbon content in a refinery co-processing petroleum and biobased feedstocks and to provide a lower detection limit that can provide more accurate measurements e.g. compared to AMS at low blending levels of a bio-component. For determining renewable carbon content in carbon-bearing refinery gas, such as fuel gas, WO2021100004A1 generally suggests using AMS, however without closer guidance.

[0010] Evidently, there is a continuous need to develop improvements in co-processing, particularly providing practical solutions to determine the biogenic carbon content in various refinery streams and products, including gaseous and gas-containing streams, even streams containing hazardous species such as H2S.

[0011] SUMMARY

[0012] 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 hydrocarbons having biogenic carbon content by processing feeds having biogenic and non-biogenic carbon content. Another aim is to provide a convenient and safe approach for determining biogenic carbon content in a gaseous or gas-containing liquid output stream of a refinery unit, even when containing hazardous species such as H2S. A further aim is to improve the overall economy of co-processing and / or the overall value of a product slate of a co-processing unit.

[0013] The appended claims define the scope of protection. Any examples and technical descriptions of apparatuses, systems, products and / or methods in the description and / or drawings not covered by the claims are presented as examples useful for understanding the invention.

[0014] Hydrogen sulfide (H2S) is a highly irritating, odorous, and toxic gas that is hazardous even at low concentrations. It irritates the eyes and airways after prolonged exposure at about 5 ppm and causes instant death at 1000-2000 ppm. H2S is commonly present in the gaseous effluent streams of various refinery units, and its removal from the refinery gases is required both for economic and safety reasons. Removal of H2S and other sour gases such as CO2, is commonly called sweetening. It would be convenient to determine the biogenic carbon content in a gaseous stream of a refinery unit only after (i.e. downstream of) the sweetening treatment, so as to avoid or reduce risks associated with handling a sample of the gaseous stream. However, after the sweetening treatment part of the biogenic carbon content is lost as sweetening removes also biogenic CO2, and also some biogenic CO may be lost during sweetening. Furthermore, to reduce investment and operating costs, it would be desired to utilise a common sweetening unit for treating gaseous streams from several conversion units of a refinery. On the other hand, e.g. for an ISCC PLUS certification it is required that the mass balancing, and biogenic carbon content determination in an output stream, is conducted for an individual conversion unit of a refinery, so determining the biogenic carbon content in the sweetened mixture of gases from several refinery units may not be helpful. Additionally, even if measuring the biogenic carbon content in such sweetened mixture of gases from several refinery units would add value of such combined gas stream, the biogenic carbon content might get too diluted for its measurement, e.g. if the share of biobased feed co-processed in an individual unit is low and / or the gaseous stream of a bio- co-processing unit is combined with high volumes of gaseous streams from conversion units processing fossil feeds, only.

[0015] The process according to the first example aspect and the system according to the second example aspect, as specified in the following, allow to reduce GHG emissions and dependence from petroleum sources, especially in the transportation and petrochemicals sectors, by providing hydrocarbons having biogenic carbon content by co-processing feeds having biogenic and non-biogenic carbon content. The sample treatment and analysis system according to the third example aspect, as specified in the following, provides a convenient and safe approach for determining biogenic carbon content in a gaseous or gas- containing stream comprising H2S and at least one or more of carbon oxide(s) and / or C1- C3 hydrocarbons, especially for use in the process according to the first example aspect. Furthermore, the present disclosure provides a convenient and safe way to conduct the mass balancing, and biogenic carbon content determination in an output stream, for individual conversion units of a refinery, as required e.g. for an ISCC PLUS certification.

[0016] According to a first example aspect, there is provided a process for producing hydrocarbons having biogenic carbon content, the process comprising: a) providing a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; b) refining the refinery feed in a conversion unit to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) subjecting the conversion effluent to separation in a separation section to obtain at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, and optionally further separating from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) subjecting the gaseous stream to a sweetening treatment to obtain a sweetened gas stream; and e1) collecting as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment or an aliquot of the unstabilised naphtha stream, e2) subjecting the sample to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably dehydrating the exhaust gas sample, e3) subjecting the exhaust gas sample preferably as dehydrated to a SOx removal treatment to obtain a SOx depleted gas sample, and optionally dehydrating the SOx depleted gas sample, and e4) subjecting at least a portion of the SOx depleted and optionally dehydrated gas sample to a biogenic carbon content determination, preferably using accelerator mass spectrometry (AMS) technique, to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream.

[0017] According to a second example aspect a system for producing hydrocarbons having biogenic carbon content is provided, the system comprising: a) at least one or more refinery feed tank(s) configured to receive a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content, or components of the refinery feed; b) a conversion unit in fluid communication with the refinery feed tank(s), and configured to receive and refine the refinery feed to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) a separation section in fluid communication with the conversion unit and configured to receive the conversion effluent and to separate therefrom at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, wherein the separation section is optionally further configured to separate from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) a sweetening unit in fluid communication with the separation section and configured to receive and sweeten the gaseous stream to obtain a sweetened gas stream; and e) a sample treatment and analysis system comprising: e1) a sampler in communication, preferably in fluid communication, with the separation section and configured to collect as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment and / or an aliquot of the unstabilised naphtha stream, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample, e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

[0018] According to a third example aspect a sample treatment and analysis system is provided, the system comprising: e1) a sampler configured to collect as a sample an aliquot of a gaseous stream and / or an aliquot of an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample, e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

[0019] According to a fourth example aspect there is provided use of a system for producing hydrocarbons having biogenic carbon content according to the second example aspect, or of a sample treatment and analysis system according to the third example aspect, in a process for producing hydrocarbons having biogenic and non-biogenic carbon content, preferably in a process according to the first example aspect.

[0020] According to a fifth example aspect there is provided use of a sample treatment and analysis system according to the third example aspect for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process for producing hydrocarbons having biogenic carbon content, wherein the gaseous stream and / or the unstabilised naphtha stream comprise H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons and is / are obtainable by separating from a conversion effluent obtained by refining in a conversion unit a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; preferably for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process according to the first example aspect.

[0021] 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.

[0022] BRIEF DESCRIPTION OF THE FIGURES

[0023] Some example embodiments will be described with reference to the accompanying figures, in which:

[0024] Fig. 1 schematically shows a sample treatment and analysis system according to an example embodiment of the present disclosure; and

[0025] Fig. 2 schematically shows a process and / or a system for producing hydrocarbons having biogenic carbon content according to an example embodiment of the present disclosure.

[0026] DETAILED DESCRIPTION

[0027] 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.

[0028] As used herein, carbon oxide(s) refer to carbon monoxide (CO) and / or carbon dioxide (CO2), and sulphur oxide(s) i.e. SOx refer to compounds consisting of sulphur and oxygen that may form in combustion, predominantly SO2. As used herein hydrocarbons refer to compounds consisting of carbon and hydrogen, including paraffins, olefins, naphthenes, and aromatics. Oxygenated hydrocarbons refer herein to hydrocarbons comprising covalently bound oxygen.

[0029] Chemically, the biogenic (renewable) or non-biogenic (non-renewable) 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 (co-)feeds, fractions, or compositions, or various blends thereof. In the present disclosure, biogenic carbon content refers to biogenic carbon content expressed as the amount of biogenic carbon in the material as a weight percent of the total carbon (TC) in the material (as may be determined e.g. in accordance with ASTM D6866-2022 or EN 16640:2017), unless otherwise stated.

[0030] 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.

[0031] 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.

[0032] 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.

[0033] The present disclosure provides a process for producing hydrocarbons having biogenic carbon content, the process comprising: a) providing a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; b) refining the refinery feed in a conversion unit to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) subjecting the conversion effluent to separation in a separation section to obtain at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, and optionally further separating from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) subjecting the gaseous stream to a sweetening treatment to obtain a sweetened gas stream; and e1) collecting as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment or an aliquot of the unstabilised naphtha stream, e2) subjecting the sample to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably dehydrating the exhaust gas sample, e3) subjecting the exhaust gas sample preferably as dehydrated to a SOx removal treatment to obtain a SOx depleted gas sample, and optionally dehydrating the SOx depleted gas sample, and e4) subjecting at least a portion of the SOx depleted and optionally dehydrated gas sample to a biogenic carbon content determination, preferably using accelerator mass spectrometry (AMS) technique, to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream.

[0034] Hydrogen sulfide (H2S) is a highly irritating, odorous, and toxic gas that is hazardous even at low concentrations. It irritates the eyes and airways after prolonged exposure at about 5 ppm and causes instant death at 1000-2000 ppm. The inherent tendency of H2S to form an acidic solution in the presence of water may lead to corrosion in equipment and pipelines causing safety issues at refineries. Its presence may also reduce the heating value of fuel gases, its combustion leading to the emission of sulfur dioxide and other harmful sulfur oxides. Its presence may also lead to poisoning of certain catalysts. Since H2S is commonly present in the gaseous effluent streams of various refinery units, its removal from the refinery gases is required both for economic and safety reasons.

[0035] Removal of H2S and other sour gases such as CO2, is commonly called sweetening. It would be convenient to determine the biogenic carbon content in a gaseous stream of a refinery unit only after (i.e. downstream of) the sweetening treatment, so as to avoid or reduce risks associated with handling a sample of gaseous stream containing H2S. However, in the sweetening treatment part of the biogenic carbon content is lost as sweetening removes also biogenic CO2, and may also remove some CO. Furthermore, to reduce investment and operating costs, it would be desired to utilise a common sweetening unit for treating gaseous streams from several refinery units of a refinery. On the other hand, e.g. for an ISCC PLUS certification it is required that the mass balancing, and biogenic carbon content determination in all output streams, including the gaseous output stream, is conducted for an individual conversion unit of a refinery, so determining the biogenic carbon content in the sweetened mixture of gases from several refinery units would not be helpful. Additionally, even if measuring the biogenic carbon content in such sweetened mixture of gases from several refinery units would add value of this combined gas stream, the biogenic carbon content might get too diluted for its measurement, e.g. if the share of biobased feed co-processed in an individual unit is low and / or the gaseous stream of a bio-co-processing unit is combined with high volumes of gaseous streams from conversion units processing fossil feeds, only.

[0036] The process according to the first example aspect and the system according to the second example aspect, as specified in the following, allow to reduce GHG emissions and dependence from petroleum sources, especially in the transportation and petrochemicals sectors, by providing hydrocarbons having biogenic carbon content, by processing feeds having biogenic and non-biogenic carbon content. The present inventors found that by utilising a sample treatment and analysis system e.g. as specified in the third example aspect, the biogenic carbon content in the gaseous or gas-containing liquid output stream of an individual conversion unit may be determined in a convenient and safe way, despite the H2S content, and essentially without losing any of the biogenic carbon content of the gaseous or gas-containing liquid stream. This is advantageous in the process and system for producing hydrocarbons having biogenic carbon content of the present disclosure, allowing to determine the actual biogenic carbon content in a gaseous or gas-containing liquid output stream of an individual conversion unit of a refinery, as may be required e.g. for an ISCC PLUS certification.

[0037] The benefits of combusting the collected sample include reducing the complexity of the sample in terms of different chemical species as well as state when the sample contains both gaseous and liquid compounds. Converting all carbon-containing compounds to CO2 makes the sample more prepared for the biogenic carbon content determination, e.g. for reduction when utilising AMS-based 14C determination with CO2-to-graphite reduction pretreatment. Some AMS-apparatuses may even determine 14C directly from CO2. Especially unstabilised naphtha may contain organic sulphur such as mercaptans in addition to H2S. As the present approach converts all the different S-species to SOx, sulphur-removal becomes more effective, allowing more complete elimination thereof. This is beneficial, as just like H2S, also SOx may interfere with CO2-to-graphite reduction. Furthermore, in biphasic samples the biogenic carbon content may be unequally distributed between the phases. This and the handling difficulties of biphasic samples increase the risk of obtaining erroneous result in the biogenic carbon content determination. No phase separation or other similar pretreatment is needed. Furthermore, while both H2S and SO2 are hazardous for humans, SO2 is not flammable and explosive like H2S, so that handling of SOx-containing streams or materials, such as spent SO2-adsorbent, is less dangerous in this respect. H2S has also much higher LD50 and LC50 compared to SO2. Further benefits of subjecting the sample to combustion will become apparent in the following.

[0038] There are several ways to provide the refinery feed having biogenic carbon content, non- biogenic carbon content and sulphur content. Such refinery feeds may be obtained for example by combining refinery feed components, wherein at least one refinery feed component has biogenic carbon content, at least one refinery feed component has non- biogenic carbon content, and at least one refinery feed component has sulphur content. Such refinery feeds may also be obtained for example by combining refinery feed components, wherein at least one refinery feed component has biogenic and non-biogenic carbon content, and at least one refinery feed component has sulphur content, or wherein at least one refinery feed component has biogenic carbon content, and at least one refinery feed component has non-biogenic carbon content and sulphur content. Some refinery feed components may have biogenic and non-biogenic carbon content, as well as sulphur content, and could be utilised alone as the refinery feed. At least part of the sulphur content of the refinery feed may originate from sulphur compounds with which the feed may be spiked to maintain a catalyst optionally used e.g. in catalytic conversion units sufficiently sulphided and active.

[0039] Examples of refinery feed components having at least biogenic carbon content include vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), used lubricating oil(s) having biogenic carbon content, and / or liquefied organic waste having biogenic carbon content. Typical vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), used lubricating oil(s) having biogenic carbon content, and / or liquefied organic waste having biogenic carbon content 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 and system 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 residues 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 side 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 used lubricating oil(s) having biogenic carbon content may comprise engine oils, driveline fluids, greases, hydraulic fluids, gear oils, switchgear oils, transformer oils, metalcutting fluids, wherein the biogenic carbon content may originate for example from ester oils, glyceridic oils, and / or HVO. The liquefied organic waste having biogenic carbon content may comprise thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied organic waste having biogenic carbon content, wherein the organic waste having biogenic carbon content may comprise waste plastics (containing e.g. some bio-based plastics), end of life tires (ELT, containing e.g. natural rubber), and / or municipal solid waste (MSW, containing e.g. biomass waste). Evidently, due to its mixed waste nature, the liquefied organic waste having biogenic carbon content typically also has non-biogenic carbon content, i.e. the liquefied organic waste may have both biogenic and non-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. 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. 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, however this may change over time when the availability of bio-based plastics increases.

[0040] If the at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulosederived biocrude(s), used lubricating oil(s) having biogenic and / or non-biogenic carbon content, and / or liquefied organic waste having biogenic and / or non-biogenic carbon content contain amounts or species of impurities that are not tolerated or preferred when refining in the conversion unit, the content of said impurities may be reduced to acceptable limits using pre-treatment methods known in the art. Exemplary pre-treatment methods suitable for the present disclosure comprise treating with mineral acids, degumming, treating with hydrogen, heat treating, deodorizing, washing with water, treating with base, demetallation, distillation, removal of solids, bleaching, and any combinations thereof.

[0041] Examples of refinery feed components having at least non-biogenic carbon content include various fossil feeds such as petroleum feeds, used lubricating oils having non-biogenic carbon content, and liquefied organic waste having non-biogenic carbon content, whereof the two latter mentioned - as explained above - may also have biogenic carbon content. Especially used lubricating oils, and thermally such as hydrothermally or by pyrolysis, or catalytically such as thermo-catalytically liquefied organic waste comprising waste plastics or ELT may have high non-biogenic carbon content. The above examples of refinery feed components having at least non-biogenic carbon content are also examples of refinery feed components that may have even significant sulphur content. However, also some of the above examples of refinery feed components having biogenic carbon content, such as tall oil or fractions or residues thereof, may have significant sulphur content, hence leading to H2S formation when refining in a conversion unit.

[0042] In certain embodiments, the refinery feed may consist of used lubricating oils and / or liquefied organic waste, having biogenic and non-biogenic carbon content, as these typically also have some sulphur content.

[0043] However, in certain preferred embodiments the refinery feed comprises at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), used lubricating oil(s) having biogenic carbon content, and / or liquefied organic waste having biogenic carbon content, and at least one or more of petroleum feed(s), used lubricating oil(s) having non-biogenic carbon content, and / or liquefied organic waste having non- biogenic carbon content. These two refinery feed (component) groups represent components typically having at least biogenic carbon content, and at least non-biogenic carbon content and sulphur content, respectively. More preferably the refinery feed comprises at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), and / or lignocellulose-derived biocrude(s) - these representing biogenic refinery components that are well-available, suitable for co-processing, and require refining e.g. due to the relatively high oxygen content, to form high-value hydrocarbon products - and at least one or more petroleum feed(s), that are not sustainable and vanishing and are hence beneficially partially substituted with biogenic materials. When utilising these refinery feed components, the benefits of the present process and systems may be seen as highest, as e.g. the thus- obtained gaseous stream is foreseen to have significant contents of H2S and biogenic CO2. In these embodiments both the conversion effluent of step b) and the gaseous stream separated in step c), as well as the optionally separated unstabilised naphtha stream, are foreseen to comprise at least H2S, carbon oxide(s) and C1-C3 hydrocarbons. In certain further preferred embodiments, the refinery feed comprises at least one or more of vegetable oil(s), animal fat(s), and / or microbial oil(s), and at least one or more petroleum feed(s). Presence of the lipidic co-feeds, typically rich in glycerides, provide the additional benefit of the glycerol-backbone forming biogenic propane particularly when subjected to hydroprocessing, which biogenic propane may end up in the gaseous stream, and can then be captured when using the present process or system(s). Particularly preferably the refinery feed comprises - as at least one refinery feed component having non-biogenic carbon content and sulphur content - at least one or more petroleum feed(s). In certain embodiments, the petroleum feed(s) comprise at least one or more of atmospheric distillate(s); atmospheric distillation bottom(s); vacuum distillate(s); distillate(s) of (hydro)cracked distillation bottom(s); atmospheric bottom(s) of (hydro)cracked distillation bottom(s); distillate(s) of (hydro)cracked vacuum distillate(s); and / or atmospheric bottom(s) of (hydro)cracked vacuum distillate(s), of a petroleum crude oil. The choice of the petroleum feed is not particularly limited, but components of lesser quality and / or having limited utility in high value applications may be preferred e.g. over straight-run petroleum distillates. In this way, the overall value of a product slate of an entire refinery may be optimised. Hence, in certain preferred embodiments, the petroleum feed comprises at least one or more of atmospheric distillation bottom(s); vacuum distillate(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric distillation bottom(s) of (hydro)cracked atmospheric and / or vacuum distillation bottom(s); atmospheric and / or vacuum distillate(s) of (hydro)cracked vacuum distillate(s); and / or atmospheric bottom(s) of (hydro)cracked vacuum distillate(s), of a petroleum crude oil.

[0044] The biogenic carbon content of the refinery feed may vary within broad ranges, typically being from 1 to 99 wt.-%, based on the total weight of carbon (TC) in the refinery feed (EN 16640:2017). In certain preferred embodiments, the refinery feed has biogenic carbon content within a range from 1 to 95 wt.-%, preferably from 3 to 90 wt.-%, more preferably from 3 to 80 wt.-%, even more preferably from 5 to 50 wt.-%, based on the total weight of carbon (TC) in the refinery feed (EN 16640:2017). When the biogenic carbon content of the refinery feed is within these ranges, due to the nature of the refinery feed components having at least biogenic carbon, and the nature of the refinery feed components having at least non-biogenic carbon, the content of H2S and / or CO2 in the gaseous stream separated from the conversion effluent are such that the benefits of the present process and systems may be seen as highest: the gaseous stream has well detectable biogenic carbon content, and depending on the feed may also contain biogenic CO2, and typically also has significant H2S content.

[0045] Also the total sulphur content of the refinery feed may vary within broad ranges, typically being at least 0.05 wt.-%, preferably at least 0.1 wt.-%, more preferably at least 0.2 wt.-%, typically within a range from 0.05 wt.-% to 2 wt.-%, preferably from 0.1 wt.-% to 2 wt.-%, more preferably from 0.2 wt.-% to 1 wt.-%, based on the total weight of the refinery feed (ASTM D7039-15a(2020)). The sulphur content of the refinery feed is known to have an influence on the deoxygenation mechanism. Already when the sulphur content of the refinery feed is somewhat elevated, such as at least 0.05 wt.-%, or more typically - especially when using petroleum feed(s) as refinery feed component(s) - at least 0.1 wt.-%, preferably at least 0.2 wt.-%, based on the total weight of the refinery feed (ASTM D7039- 15a(2020)), the oxygen atom cleavage, i.e. deoxygenation, via decarboxylation and decarbonylation reactions may get more and more favoured over hydrodeoxygenation, thereby providing higher carbon oxide content in the gaseous stream. Since oxygen atoms are typically abundant in refinery feed components having at least biogenic carbon content, particularly in vegetable oil(s), animal fat(s), microbial oil(s), and / or lignocellulose-derived biocrude(s), the carbon in CO2 molecules present in the gaseous stream is largely biogenic and hence the present process and systems are particularly advantageous as capturing this content.

[0046] Also the oxygen content of the refinery feed may vary within broad ranges, typically being at least 0.1 wt.-%, preferably at least 0.5 wt.-%, more preferably at least 1 wt.-%, typically within a range from 0.1 wt.-% to 15 wt.-%, preferably from 0.5 wt.-% to 10 wt.-%, more preferably from 1 wt.-% to 8 wt.-%, based on the total weight of the refinery feed (ASTM D5622-2017).

[0047] When the refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content is refined in a conversion unit, heteroatoms covalently bound in organic compounds, particularly oxygen atoms typically abundant in refinery feed components having at least biogenic carbon content, and sulphur atoms typically abundant in refinery feed components having at least non-biogenic content, are cleaved forming H2S and carbon oxides. At the same time hydrocarbons are formed, typically both hydrocarbons that are gaseous at NTP, such as C1-C3 hydrocarbons, and hydrocarbons that are not gaseous at NTP, but e.g. liquid. While formation of hazardous H2S may be seen as undesired, cleavage of sulphur from the feed components is necessary to obtain low-sulphur hydrocarbons meeting requirements for various uses such as for use in fuels. In refinery conversion processes this typically leads to H2S formation. Additionally, refinery feed components having sulphur content may also be process-wise beneficial, for example for keeping a catalyst optionally utilised in a conversion unit sufficiently sulphided and hence active, even without separate sulphur spiking.

[0048] In the present process and system, the refinery feed is refined in a conversion unit to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably carbon oxide(s). The refining may be arranged in a single refining stage or it may comprise multiple refining stages arranged in multiple refining zones in a conversion unit. In other words, the refining may comprise e.g. catalytic hydroprocessing, catalytic cracking, and / or thermal cracking arranged in catalytic hydroprocessing zone(s), catalytic cracking zone(s), and / or thermal cracking zone(s) in a conversion unit. Whether the refining in the conversion unit is arranged in a single refining stage or multiple refining stages in multiple refining zones, these refining stages or zones may be arranged in one or more reactors. The number of 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.

[0049] In certain preferred embodiments, the refining includes at least one or more of catalytic hydroprocessing, catalytic cracking, and / or thermal cracking, preferably at least catalytic hydroprocessing, more preferably catalytic hydroprocessing comprising at least catalytic hydrotreatment. In these embodiments the conversion unit may comprise one or more catalytic hydroprocessing zone(s), catalytic cracking zone(s), or thermal cracking zone(s). All these refining types are well known, and include technologies capable of cleaving heteroatoms from organic compounds. When using only one refining type in a conversion unit, the gaseous stream may have more coherent composition, simplifying its treatment. The hydroprocessing, as used in the present disclosure, may encompass for example hydrotreatment and / or hydrocracking. By catalytic cracking is meant herein conversion processes encompassing catalytic cracking not consuming added hydrogen, such as fluid catalytic cracking (FCC) or catalytic pyrolysis, and by thermal cracking is meant herein conversion processes based on elevated temperature in the absence of catalyst, such as (non-catalytic) pyrolysis.

[0050] In certain preferred embodiments, the refining includes catalytic hydroprocessing, as in catalytic hydroprocessing, such as catalytic hydrotreatment and / or catalytic hydrocracking, the heteroatom cleavage may be more efficient and selective, and upon cleavage e.g. sulphur forms rather H2S than other sulphur compounds. In certain particularly preferred embodiments, the refining includes catalytic hydroprocessing comprising catalytic hydrotreatment, as utilising catalytic hydrotreatment rather than dedicated catalytic hydrocracking, may help to reduce formation of C1-C2 gases, that are generally regarded as lower value products e.g. compared to liquid hydrocarbons, and thereby to improve yield of conversion products having longer carbon chains. Conversion effluents from catalytic hydrotreatment may also have elevated C3 contents, when the refinery feed comprises fatty materials containing glycerol-backbone in their structure.

[0051] By hydrotreatment is meant herein a process of treating organic material by means of molecular hydrogen in the presence of a hydrotreatment catalyst. The hydrotreatment reactions may include removal of oxygen from oxygenated hydrocarbons as water i.e. hydrodeoxygenation (HDO), sulphur from organic sulphur compounds as dihydrogen sulphide (H2S), i.e. hydrodesulphurisation, (HDS), nitrogen from organic nitrogen compounds as ammonia (NH3), i.e. hydrodenitrogenation (HDN), halogens, for example chlorine from organic chloride compounds as hydrochloric acid (HCI), i.e. hydrodechlorination (HDCI), and / or metals by hydrodemetallization; and / or hydrogenation of olefinic bonds to saturated bonds and / or of aromatics to naphthenes. Depending e.g. on the composition of the feed fed to the hydrotreatment, different reactions may occur and / or prevail in the hydrotreatment. 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.

[0052] By hydrocracking is meant herein a catalytic process of treating organic material in the presence of molecular hydrogen, causing the feed molecules to crack into smaller, lower- boiling compounds. The presence of hydrogen ensures reduced olefin formation. Hydrocracking may also involve ring-opening of cyclic feed components, as well as cleavage of heteroatoms. Depending on the feed composition, hydrocracking conditions and the used catalyst, isomerisation reactions may also occur during hydrocracking. Unlike for hydrotreatment catalysts, at least some acidity is required for a hydrocracking catalyst, which may be attained e.g. by using acidic materials and / or incorporating promoters such as certain metals, as is well known in the art.

[0053] In exemplary embodiments, the refining includes catalytic hydroprocessing comprising catalytic hydrotreatment, wherein the hydrotreatment is conducted at a temperature within a range from 250 °C to 500 °C, preferably from 300 °C to 450 °C, a pressure within a range from 1 MPa to 20 MPa, preferably from 5 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrotreatment reactor within a range from 1 MPa to 20 MPa, preferably from 5 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg refinery feed per kg hydrotreatment catalyst per hour, and a H2 to refinery feed ratio within a range from 50 to 2000, preferably from 100 to 1500 normal liters H2 per liter refinery 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, a relatively high hydrogen pressure in the hydrotreatment may help to minimise presence and formation of olefins, thereby contributing i.a. to improved stability of the degassed hydrocarbon stream and products recovered therefrom. The hydrotreatment catalyst may be any conventionally used hydrotreatment catalyst or combination thereof. Typical hydrotreatment catalyst may comprise 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, such as NiMo, CoMo, NiCoMo, NiW, and / or NiMoW, preferably on a support such as alumina.

[0054] In exemplary embodiments, the refining includes catalytic hydroprocessing comprising catalytic hydrocracking, wherein the hydrocracking is conducted at a temperature within a range from 280 °C to 450 °C, preferably from 300 °C to 420 °C, a pressure within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a H2 partial pressure at the inlet of the hydrocracking reactor within a range from 8 MPa to 20 MPa, preferably from 12 MPa to 18 MPa, a weight hourly space velocity within a range from 0.1 to 10, preferably from 0.2 to 8 kg refinery feed per kg hydrocracking catalyst per hour, and a H2 to refinery feed ratio within a range from 50 to 2000, preferably from 500 to 1500 normal liters H2 per liter refinery feed, in the presence of a hydrocracking catalyst. Within these conditions the efficiency of the hydrocracking step in terms of selectivity and / or activity regarding hydrocracking reactions may be further enhanced, sufficient heteroatom removal attained, hydrocracking catalyst deactivation controlled, undesired side reactions suppressed and desired conversion level reached. For example, a relatively high hydrogen pressure in the hydrocracking may help to minimise presence and formation of olefins, thereby contributing i.a. to improved stability of the degassed hydrocarbon stream and products recovered therefrom. The hydrocracking catalyst may be any conventionally used hydrocracking catalyst or combination thereof. Typically, the hydrocracking catalyst is a bifunctional hydrocracking catalyst comprising at least one or more metal, and at least one or more acidic porous material.

[0055] In the present process and system for producing hydrocarbons having biogenic carbon content, the conversion effluent is subjected to separation in a separation section to obtain at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream. Optionally at least one or more distillate(s) and a separation bottom are further separated from the degassed hydrocarbon stream. Typically, the separation is conducted in several steps in the separation section. Although the gaseous stream is herein referred to as singular, it is understood that in practice several gaseous streams comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons may be separated in the separation section. At least one, preferably all of these gaseous streams separated in the separation section is / are subjected to the sweetening treatment and sampled for processing according to steps e1)-e4) I in the sample treatment and analysis system. At least some of these gaseous streams separated in the separation section may be combined before subjecting to sweetening, while some others may be sweetened alone. In the separation, water that may form during the refining in the conversion unit, e.g. in the course of deoxygenation of oxygenated hydrocarbons, is typically also separated and removed. The separation to obtain at least the gaseous stream may be referred to as a gas-liquid separation as allowing recovery of compounds that are gaseous under the separation conditions. An initial gas-liquid separation may be conducted for example as an integral step within the conversion unit, such as in the (last) conversion reactor of the conversion unit, although usually conducted as a separate step. Typically, the separation steps are conducted at different temperatures within a range from 0 °C to 500 °C, such as from 15°C to 300°C. Preferably at least the initial gas-liquid separation step is conducted at essentially same pressure as that of the (last) reactor in the conversion unit wherefrom the effluent originates. Typically, the pressure during the separation steps may be within a range from 0.1 MPa to 20 MPa, such as from 1 MPa to 18 MPa. In certain preferred embodiments, the conversion effluent is subjected to the separation utilising at least one or more of high pressure high temperature separator(s), high pressure low temperature separator(s), high pressure medium temperature separator(s), low pressure high temperature separator(s), low pressure medium temperature separator(s), low pressure low temperature separator(s), stripper(s), gas scrubber(s), gas knock out drum(s), horizontal separator(s), vertical separator(s), three-phase separator(s), cyclone separator(s), centrifugal separator(s), and / or gunbarrel tank(s), to obtain the gaseous stream(s) comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons.

[0056] In addition to an initial gas-liquid separation, in certain preferred embodiments the separation in step c) may further include removing from the gaseous stream at least part of hydrocarbons having 8 or more carbon atoms, preferably at least part of hydrocarbons having 7 or more carbon atoms, more preferably at least part of hydrocarbons having 6 or more carbon atoms, even more preferably at least part of hydrocarbons having 5 or more carbon atoms, as may be entrained in the gaseous stream, before collecting in step e1) an aliquot of the gaseous stream as a sample. This may be attained for example by condensating the gaseous stream e.g. using high pressure and / or lowered temperature, and distilling and / or flashing the condensate, or by using centrifugal separation, or by any other conventionally used methods. For example, the reactor effluent may be subjected to initial gas-liquid separation in a high pressure medium temperature separator to obtain a liquid intermediate stream and a gaseous stream, and subjecting the latter to separation in a high pressure low temperature separator to remove condensed hydrocarbons. By including in the separation section removal of at least part of the heaviest hydrocarbons that may be present in the gaseous stream(s), valuable further liquid intermediate stream(s) may be obtained usable e.g. as gasoline fuel component and / or as a co-feed to a hydrogen production unit such as steam reforming to obtain syngas, followed by recovering a makeup hydrogen stream from the syngas. The biogenic carbon content in such further liquid intermediate stream(s) may be determined using conventional methods, preferably using AMS technique. Alternatively, the liquid intermediate stream(s) obtained in the separation section may be combined to obtain the degassed hydrocarbon stream, optionally after subjecting to further separation e.g. in a stripper.

[0057] In the separation section also an unstabilised naphtha stream, sometimes referred to as a wild naphtha, may be separated. Such unstabilised naphtha stream may have significant content of residual gases in addition to naphtha boiling range liquid hydrocarbons, these gases typically comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons. Such unstabilised naphtha stream may be separated for example using a stripper, where also the degassed hydrocarbon stream may be obtained. Due to the biphasic nature and presence of gases and especially H2S, the biogenic carbon content determination of an unstabilised naphtha sample is not straight-forward. However, for the present process and systems the biphasic nature of the sample is not a problem, but gaseous and gas-containing liquid samples can be processed in the same way.

[0058] In addition to H2S, carbon oxide(s) and C1-C3 hydrocarbons, exemplary compounds that may also be retained in the gaseous or gas-containing stream separated from the conversion effluent include at least one or more of hydrogen and / or ammonia. Particularly when the refining is hydroprocessing, the conversion effluent may be rich in residual hydrogen.

[0059] In the present process and system for producing hydrocarbons having biogenic carbon content the separated gaseous stream is subjected to a sweetening treatment to obtain a sweetened gas stream. As discussed in the foregoing, in practice, several gaseous streams comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons may be separated in the separation section, some of which may be combined before subjecting to sweetening, while some others may be sweetened alone. In certain preferred embodiments, in step d) the sweetening treatment comprises at least absorption. Sweetening treatment involving absorption is preferred as absorption into liquid solvent(s) is cost-efficient, very commonly used in refineries for acid gas removal, various liquid solvent absorbents exist, as well as efficient regeneration procedures for them. When the sweetening treatment comprises absorption, the absorption may be conducted using any suitable liquid absorbents including common physical solvents such as methanol (e.g. Rectisol), dialkyl ethers of polyethylene glycol (e.g. Selexol), sulfolane, N-methyl-2- pyrrolidone (e.g. Purisol), propylene carbonate (e.g. Fluor Solvent), morpholine derivatives (e.g. Morphysorb); alkanolamines including primary amines such as monoethanolamine (MEA), diglycolamine (DGA) or 2-amino-2-methyl-1-propanol (AMP), secondary amines such as diethanolamine (DEA) or diisopropanolamine (DI PA), tertiary amines such as N- methyldiethanolamine (MDEA) or triethanolamine (TEA); ionic liquids that are liquids composed of ions; deep eutectic solvents that are multicomponent mixtures of hydrogen bond acceptors and donors; or any combinations thereof, optionally with additives. Various other sweetening treatments are also commonly known, and may be used in the sweetening treatment of the present process and system in addition or instead of absorption. However, in certain particularly preferred embodiments, the sweetening treatment comprises at least absorption using at least one or more of physical solvent(s) and / or alkanolamine(s).

[0060] Additionally or alternatively, in certain preferred embodiments in step d) the sweetening treatment is conducted in a common sweetening unit receiving the gaseous stream and one or more further gaseous stream(s) separated from further conversion effluent(s) obtained by refining further refinery feed(s) in further conversion unit(s). Utilising a common sweetening unit for at least some of the gaseous streams separated in the separation section and further gaseous stream(s) separated from further conversion effluent(s), provides decreased investment and operating costs as further benefits.

[0061] In certain preferred embodiments, before the gaseous stream is subjected to the sweetening treatment (i.e. upstream of the sweetening treatment), but after (i.e. downstream of) the aliquot of the gaseous stream is collected in step e1), the gaseous stream is combined with one or more further gaseous stream(s) separated from further conversion effluent(s) obtained by refining further refinery feed(s) in further conversion unit(s), wherein the further gaseous stream(s) optionally has / have lower biogenic carbon content than the gaseous stream or essentially no biogenic carbon content, and the gaseous stream is subjected to the sweetening treatment in step d) as combined with said further gaseous stream(s). The further conversion effluent(s) may be obtained by refining further refinery feed(s) in further conversion unit(s), wherein the refining in the further conversion unit(s) may be selected from further catalytic hydroprocessing, further catalytic cracking, and further thermal cracking, preferably from further catalytic hydroprocessing, more preferably from further catalytic hydroprocessing comprising further catalytic hydrotreatment, for similar reasons as discussed in connection with the refining in the conversion unit of step b). The further gaseous stream(s) separated from further conversion effluent(s) may contain similar compounds as the gaseous stream separated in step c) i.e. at least one or more of H2S, carbon oxide(s), C1-C3 hydrocarbons, hydrogen, and / or ammonia. Utilising a common sweetening unit provides the further benefits of decreasing investment and operating costs, but combining the gaseous stream having biogenic carbon content with further gaseous stream(s) having lower or no biogenic carbon content may dilute the biogenic carbon content of the gaseous stream below the detection limit of the biogenic carbon content determination, hence underlining the advantages of the present process and systems.

[0062] The sweetened gas stream may be subjected to typical refinery gas treatments, depending on the composition of the gaseous stream. In certain embodiments, the sweetened gas stream is subjected at least to hydrogen recovery in a hydrogen recovery unit to obtain a recycle hydrogen stream and / or to recovery of a gas stream containing C1-C3 hydrocarbons, wherein at least a portion of the gas stream containing C1-C3 hydrocarbons, and optionally C5-C8 hydrocarbons removed from the gaseous stream in step c), is / are fed to a hydrogen production unit, preferably to a steam reforming unit, to obtain syngas, followed by recovering a make-up hydrogen stream. In certain further embodiments, the refining in step b) comprises catalytic hydroprocessing, and at least a portion of the recovered recycle hydrogen stream and / or of the recovered make-up hydrogen stream is fed to the catalytic hydroprocessing. These embodiments provide further enhancement of the process economy and sustainability.

[0063] The present process involves e1) collecting as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment (i.e. upstream of the sweetening treatment) or an aliquot of the unstabilised naphtha stream; e2) subjecting the sample to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably dehydrating the exhaust gas sample; e3) subjecting the exhaust gas sample preferably as dehydrated to a SOx removal treatment to obtain a SOx depleted gas sample, and optionally dehydrating the SOx depleted gas sample; and e4) subjecting at least a portion of the SOx depleted and optionally dehydrated gas sample to a biogenic carbon content determination, preferably using accelerator mass spectrometry (AMS) technique, to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream. WO2021100004A1 teaches that due to long analysis times, instrument cost, and tedious sample preparation methods, AMS technique, and ASTM standard D6866 methods, would be unsuitable for implementing the technique in a refinery. However, the present inventors have found that steps e1) to e4) of the present process / system and / or the present sample treatment and analysis system provide not only safe but also convenient i.e. sufficiently robust way to determine biogenic carbon content also in the gaseous and gas-containing output streams comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, of a refinery conversion unit, even when utilising a biogenic carbon content analyzer using AMS technique.

[0064] The sequence of steps e1) to e4) does not need to be conducted continuously during the running of the present process or when using the present systems. Preferably the sequence of steps e1) to e4) is conducted intermittently, i.e. from time to time or as campaigns, preferably on a need basis such as when changes in the composition of the separated gaseous stream(s) and in the optionally separated unstabilised naphtha stream are foreseen. Since conducting the sequence of steps e1) to e4) is initiated by collecting as a sample an aliquot of the gaseous stream or of the unstabilised naphtha stream, in certain preferred embodiments, in step e1) the aliquots of the gaseous stream and / or of the unstabilised naphtha stream are collected intermittently. Examples of situations where changes in the composition of the separated gaseous stream(s) and in the optionally separated unstabilised naphtha stream may be foreseen include changes in the composition of the refinery feed, changes in the operating conditions of the conversion unit, changes in the activity and / or selectivity of a catalyst optionally used in the refining in the conversion unit, and / or changes in the operating conditions of the separation section. When the sequence of steps e1) to e4) is conducted intermittently during the running of the present process / system, the steps e1) to e4), particularly collecting of the aliquots of the gaseous stream and / or of the optionally separated unstabilised naphtha stream, may be conducted periodically i.e. approximately within fixed intervals or occasionally i.e. within varying intervals. The sequence of steps e1) to e4), particularly collecting of the aliquots of the gaseous stream and / or of the optionally separated unstabilised naphtha stream to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream, respectively, may be conducted more frequently when taking the present process / system in use. The present process / system may also involve creating a database containing information on the obtained content of biogenic carbon in the gaseous stream and / or in the optionally separated unstabilised naphtha stream, as well as on the respective refinery feed composition, operating conditions in the conversion unit, selectivity and / or activity and / or time-on-stream of an optionally used catalyst, and / or operating conditions in the separation section at the time; using the database for creating and / or training a model for estimating the biogenic carbon content in the gaseous stream and / or in the optionally separated unstabilised naphtha stream; and at times when not conducting the sequence of steps e1) to e4), using the model for obtaining the biogenic carbon content in the gaseous stream and / or in the optionally separated unstabilised naphtha stream. In these embodiments, the sequence of steps e1) to e4), particularly collecting of the aliquots of the gaseous stream and / or of the optionally separated unstabilised naphtha stream, may be conducted from time to time to revalidate or calibrate the model. The benefits of collecting the aliquots of the gaseous stream or of the optionally separated unstabilised naphtha stream intermittently include reduced risk of exposure of personnel to H2S, and reduced costs of operating steps e1) to e4) as well as possibility to use the same sample treatment and analysis system in determining biogenic carbon content in multiple separated gaseous steams and unstabilised naphtha stream, one at a time, even to serve multiple different refinery units. In certain embodiments, the aliquots of the gaseous stream(s) or the aliquots of the optionally separated unstabilised naphtha stream are collected in the separation section or thereafter, preferably from a separator, vessel or pipeline having low pressure.

[0065] In step e2) the sample is subjected to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably the exhaust gas sample is dehydrated. The combustion is conducted in order to convert essentially all carbon present in the sample to CO2 and essentially all sulphur present in the sample to SOx, especially to SO2. Converting essentially all carbon to CO2 simplifies the 14C measurement, as e.g. some AMS-apparatuses may determine 14C directly from CO2, and even when using the CO2-to-graphite reduction approach, all the carbon is in the CO2 form and ready for reduction. Converting essentially all sulphur to SOx allows its effective removal in step e3). Just like H2S, also SOx may interfere with the sample preparation and / or biogenic carbon content determination, especially when using accelerator mass spectrometry (AMS) technique. More specifically, depending on the AMS-apparatus, SOx may negatively influence the CO2-to-graphite reduction in the sample preparation for biogenic carbon content measurement by AMS technique, even leading to an erroneous result. Furthermore, while both H2S and SO2 are hazardous for humans, SO2 is not flammable and explosive like H2S, so that handling of SOx-containing streams or materials, such as spent SO2-adsorbent, is less dangerous in this respect. H2S has also much higher LD50 and LC50 compared to SO2. Further benefits of subjecting the sample to combustion will become apparent in the following. In step e3) the exhaust gas sample is subjected, preferably as dehydrated, to a SOx removal treatment. In certain preferred embodiments, the SOx removal treatment comprises i) selective adsorption of SOx; ii) selective adsorption or absorption of CO2 followed by recovery of the adsorbed or absorbed 002; or iii) cryogenic removal of SOx based on the boiling point difference of SOx and 002, to obtain the SOx depleted gas sample. The selective adsorption of SOx is preferably conducted with at least one or more selectively SOx-adsorbing single metal oxide(s), mixed metal oxides, metal oxide(s) supported on carbonaceous material(s), clay(s), zeolite(s), zeolite-type material(s) and / or porous organic polymers, for example by passing the exhaust gas sample through a bed of SOx-adsorbing granules. The selective adsorption or absorption of 002 is preferably conducted with at least one or more selectively CO2-adsorbing or CO2-absorbing metal organic framework adsorbent(s) (MOFs), organic polymer(s), inorganic adsorbent(s), carbonaceous adsorbent(s), physical solvent(s), amine(s), ionic liquid(s), and / or nanoparticle dispersion(s), advantageously with at least one or more selectively 002- adsorbing inorganic adsorbent(s) and / or carbonaceous adsorbent(s). The selective adsorption or absorption of 002 is followed by recovery of the adsorbed or absorbed 002. For illustration, the SOx removal treatment in step e3) comprising selective adsorption or absorption of 002 may be conducted by contacting the exhaust gas sample with 13X zeolite, which is an inorganic adsorbent, or with Fe-BTC, UiO-66 or Cll-BTC, that are MOF adsorbents, followed by recovery of the adsorbed 002 e.g. by heating. Most preferably, selective adsorption of 002 by reversible physisorption is utilised for easy recovery of the adsorbed 002. The cryogenic removal of SOx based on the boiling point difference of SOx and 002 may be conducted for example by passing the exhaust gas sample through a tube under cryogenic conditions causing condensation of the SOx, and any water if present, while 002 remains gaseous and continues through the tube. The condensed material may be released from the tube in a controlled manner e.g. by heating the tube. Cryogenic removal of SOx is effective, as S02 has significantly higher boiling point, -10 °C, and S03 even higher boiling point, 45 °C, compared to C02 which boils at -78.5 °C. This approach would not be effective for non-combusted samples, as C02 and H2S boil at quite similar temperatures, at -78.5 °C and -60 °C, respectively.

[0066] Optionally, the present process and systems may involve dehydrating the exhaust gas sample in step e2) and / or dehydrating the SOx depleted gas sample in step e3). Dehydrating the exhaust gas sample in step e2) is preferred when the SOx removal treatment of step e3) comprises i) selective adsorption of SOx or ii) selective adsorption or absorption of C02 with such an adsorbent or absorbent where H20 would compete with the SOx or CO2 in getting adsorbed / absorbed. Additionally, dehydrating the exhaust gas sample after combustion may help to reduce or avoid formation of highly corrosive H2SO4 by SOx dissolved in the moisture present in the exhaust gas. Alternatively or additionally, dehydrating the SOx depleted gas sample in step e3) may be preferred if the SOx removal treatment of step e3) comprises i) selective adsorption of SOx or ii) selective adsorption or absorption of CO2 with such an adsorbent or absorbent that generates H20 upon the adsorption / absorption, e.g. involving chemisorption. In certain particularly preferred embodiments, the present process and systems involve dehydrating the exhaust gas sample in step e2) and dehydrating the SOx depleted gas sample in step e3) so as to minimise risk of H2SO4 formation, to maximise effectiveness of the SOx removal treatment of step e3), and to minimise effect on gas chromatography (GO) (or elemental analyser) when used. Inorganic salts are known for their usability for water removal. However, their reactions with water are exothermic. Hence, in certain preferred embodiments, the dehydration in step e2) and / or step e3) is conducted using at least one or more synthetic polymers, preferably synthetic ionomers (i.e. synthetic polymers with ionic properties), more preferably sulfonated tetrafluoroethylene-based fluoropolymer-copolymers, such as Nation incorporating perfluorovinyl ether groups terminated with sulfonate groups onto a tetrafluoroethylene (PTFE) backbone. Synthetic polymers are not consumed in the cause of dehydration, and no reagent replacements are needed.

[0067] The present process / systems may also involve subjecting any of the streams / samples of steps e1) to e4) to a composition analysis using gas chromatography (GC). Subjecting to a composition analysis using GC for example a portion of the exhaust gas sample and / or a portion of the SOx depleted gas sample, preferably as dehydrated, may be useful for validating completeness of the combustion or of the SOx removal, or for verifying that after the SOx removal the composition remains otherwise essentially unchanged. Composition analysis using GC may also be utilised for validating integrity of the sample treatment and analysis system. As presence of water / moisture may be harmful for GC, the composition analysis is preferably conducted after dehydration. In certain preferred embodiments, the present process and systems include subjecting a portion of the SOx depleted and preferably dehydrated gas sample to a composition analysis using gas chromatography (GC), to validate completeness of the SOx removal.

[0068] Thereafter, the present process and systems involve subjecting at least a portion of the SOx depleted and optionally dehydrated gas sample to a biogenic carbon content determination, preferably using accelerator mass spectrometry (AMS) technique, to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream. AMS is preferred due to its preciseness, even for gaseous samples. As used herein, the biogenic carbon content determination or analyzer, whether using AMS or another technique, is to be understood as including the usual sample preparation steps that are well known for the selected technique. For example, the sample preparation for AMS technique may involve reduction of the CO2 to graphite. However, a usual sample preparation step of oxidizing all carbon present in the sample to CO2 is not necessary because of the combustion in step e2). As the results are presented as the biogenic carbon mass percentage of the total carbon of the sample, combustion and removal of SO2, H2O or other non-carbon containing component from the sample holds no significance to the biogenic carbon content therein, and consequently removal of non-carbon containing compounds does not require e.g. any corrective calculations.

[0069] From the degassed hydrocarbon stream separated from the conversion effluent in step c), at least one or more distillate(s) and a separation bottom may be further separated, for example using distillation, steam stripping, and / or any other technology conventionally used for fractionation. In certain preferred embodiments, at least one or more distillate(s) and a separation bottom are further separated from the degassed hydrocarbon stream, and the biogenic carbon content in all the separated distillate(s) and in the separation bottom are determined, preferably using AMS technique.

[0070] The present disclosure also provides a system for producing hydrocarbons having biogenic carbon content, the system comprising: a) at least one or more refinery feed tank(s) configured to receive a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content, or components of the refinery feed; b) a conversion unit in fluid communication with the refinery feed tank(s), and configured to receive and refine the refinery feed to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) a separation section in fluid communication with the conversion unit and configured to receive the conversion effluent and to separate therefrom at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, wherein the separation section is optionally further configured to separate from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) a sweetening unit in fluid communication with the separation section and configured to receive and sweeten the gaseous stream to obtain a sweetened gas stream; and e) a sample treatment and analysis system comprising: e1) a sampler in communication, preferably in fluid communication, with the separation section and configured to collect as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment and / or an aliquot of the unstabilised naphtha stream, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample, e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

[0071] The present disclosure also provides a sample treatment and analysis system comprising: e1) a sampler configured to collect as a sample an aliquot of a gaseous stream and / or an aliquot of an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample, e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

[0072] It should be appreciated that while the units utilised in steps e1) to e4) are preferably arranged in fluid communication, at least some of them may be arranged in communication requiring e.g. manual input. For example, the sample may be delivered to the combustion unit manually, and / or the exhaust gas sample preferably as dehydrated may be delivered to the SOx removal unit manually, and / or at least a portion of the SOx depleted and optionally dehydrated gas sample may be delivered to the biogenic carbon content analyzer manually, just to name a few examples where other than fluid communication may be utilised. Particularly when the aliquots of the gaseous stream and / or of the unstabilised naphtha stream are collected intermittently, e.g. with long intervals, arranging at least some of the communications manually may even be preferred, as not requiring investment in the connecting hardware and allowing more flexible use of the units when not being used according to the present process and systems. Furthermore, the communication is not necessarily direct but may be arranged indirectly such as via another unit. For example, the biogenic carbon content analyzer may be in communication with the SOx removal unit via an optional drying unit.

[0073] According to the present disclosure, there is also provided use of the system for producing hydrocarbons having biogenic carbon content according to the second example aspect, or of the sample treatment and analysis system according to the third example aspect, in a process for producing hydrocarbons having biogenic and non-biogenic carbon content, preferably in a process according to the first example aspect. According to the present disclosure, there is further provided use of the sample treatment and analysis system according to the third example aspect for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process for producing hydrocarbons having biogenic carbon content, wherein the gaseous stream and / or the unstabilised naphtha stream comprise H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons and is / are obtainable by separating from a conversion effluent obtained by refining in a conversion unit a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; preferably for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process according to the first example aspect. Such a model may be created and / or trained for example based on a database as explained in the foregoing. Hence, in certain preferred embodiments of the process according to the first example aspect, the sample treatment and analysis system according to the third example aspect is used for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process for producing hydrocarbons having biogenic carbon content comprising at least steps a) to c) of the process according to the first example aspect.

[0074] In embodiments of the system according to the second example aspect, any one or more of the refinery feed, the refinery feed components, the conversion unit, the conversion effluent, the separation or separation section, the gaseous stream or the unstabilised naphtha stream comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, the degassed hydrocarbon stream, the one or more distillate(s), the separation bottom, the sweetening treatment or unit, the sweetened gas stream, the sample treatment and analysis system, the sampler, the sample, the combustion or combustion unit, the exhaust gas sample preferably as dehydrated, the SOx removal treatment or unit, the SOx depleted and optionally dehydrated gas sample, dehydrating the exhaust gas sample (with the first drying unit), dehydrating the SOx depleted gas sample (with the second drying unit), the gas chromatography (GO) analyzer or composition analysis, and / or the biogenic carbon content determination or analyzer, may be as specified in the present disclosure in connection with the embodiments of the process according to the first example aspect and / or in connection with the embodiments of the sample treatment and analysis system according to the third example aspect. Similarly, in embodiments of the sample treatment and analysis system according to the third example aspect, any one or more of the sampler, the sample, the gaseous stream or the unstabilised naphtha stream comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, the combustion or combustion unit, the exhaust gas sample preferably as dehydrated, the SOx removal treatment or unit, the SOx depleted and optionally dehydrated gas sample, dehydrating the exhaust gas sample (with the first drying unit), dehydrating the SOx depleted gas sample (with the second drying unit), the gas chromatography (GC) analyzer or composition analysis, and / or the biogenic carbon content determination or analyzer, may be as specified in the present disclosure in connection with the embodiments of the process according to the first example aspect and / or in connection with the embodiments of the system according to the second example aspect. Further similarly, in embodiments of the use according to the fourth example aspect or the fifth example aspect, the process for producing hydrocarbons having biogenic carbon content, or any steps or features of the process such as the gaseous stream and / or the unstabilised naphtha stream, may be as specified in the present disclosure in connection with the embodiments of the process according to the first example aspect.

[0075] Schematic presentation of the process and the systems

[0076] Fig. 1 schematically shows a sample treatment and analysis system according to an example embodiment. Fig 1 shows a sampler 300 configured to collect as a sample 200 an aliquot of a gaseous stream 30 and / or an aliquot of an unstabilised naphtha stream 40 both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, and a combustion unit 310 in communication with the sampler 300 and configured to receive and combust the sample 200 to obtain an exhaust gas sample 210 containing CO2, sulphur oxide(s) (SOx) and H2O. Preferably a first drying unit 320 is arranged in communication with the combustion unit 310 and configured to receive and dehydrate the exhaust gas sample 210 to obtain a dehydrated exhaust gas sample 220. This is foreseen to minimise or prevent H2SO4 formation from the SOx and H2O. A SOx removal unit 330 is then arranged in communication with the combustion unit 310 preferably via the first drying unit 320, and configured to receive the exhaust gas sample 210, 220 preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample 230. An optional second drying unit 340 may be arranged in communication with the SOx removal unit 330 and configured to receive and dehydrate the SOx depleted gas sample 230. A biogenic carbon content analyzer 350, preferably using accelerator mass spectrometry (AMS) technique, is arranged in communication with the SOx removal unit 330, optionally via the second drying unit 340, and configured to receive at least a portion of the SOx depleted gas sample 230, or the SOx depleted and dehydrated gas sample 240, and to determine its biogenic carbon content. Based on the output value of the biogenic carbon content analyzer 350, the content of biogenic carbon in the gaseous stream 30 or in the unstabilised naphtha stream 40 is obtained, as a wt.-% based on the total weight of carbon (TO) in the respective stream. Additionally, the sample treatment and analysis system may comprise an optional gas chromatography (GC) analyzer (not shown in Figure 1). Advantageously the GC analyzer is arranged in communication with the SOx removal unit 330, preferably via the second drying unit 340, and configured to receive a portion of the SOx depleted gas sample 230, preferably the SOx depleted and dehydrated gas sample 240, to be subjected to a composition analysis.

[0077] Fig. 2 schematically shows a process and a system for producing hydrocarbons having biogenic carbon content, according to an example embodiment. Fig. 2 shows at least one or more refinery feed tank(s) 100, 110 configured to receive a refinery feed 10 having biogenic carbon content, non-biogenic carbon content and sulphur content, or components thereof. The refinery feed 10 having biogenic carbon content, non-biogenic carbon content and sulphur content is refined in a conversion unit 120 to obtain a conversion effluent 20 comprising at least H2S and hydrocarbons, and preferably carbon oxide(s). The conversion effluent 20 is then subjected to a separation in a separation section to obtain at least a gaseous stream 30 and optionally an unstabilised naphtha stream 40 both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream 400. In practice several gaseous streams 30 may be separated, for example using a plurality of conventional separators such as high pressure high temperature, high pressure low temperature, high pressure medium temperature, low pressure high temperature, low pressure medium temperature, and / or low pressure low temperature separator(s). Additionally or alternatively, a gaseous stream 30 and an unstabilised naphtha stream 40 may be separated for example using a stripper. The degassed hydrocarbon stream 400 may be utilised as such, or optionally the separation may further include separating from the degassed hydrocarbon stream 400 at least one or more distillate(s) 410, 420 and a separation bottom 430, for example using a distillation column 140. The gaseous stream 30 is subjected to a sweetening treatment in a sweetening unit 150 to remove sour gases 60, such as H2S and CO2, and to obtain a sweetened gas stream 70. The gaseous stream 30 may be subjected to the sweetening treatment alone, or as combined with one or more further gaseous stream(s) 50 separated from further conversion effluent(s) obtained by refining further refinery feed(s) in further conversion unit(s). Optionally the sweetened gas stream 70 may be subjected to hydrogen recovery in a hydrogen recovery unit 160 to obtain a recycle hydrogen stream 80 and a gas stream 90 containing C1-C3 hydrocarbons. Before (i.e. upstream of) subjecting the gaseous stream 30 to the sweetening treatment, and preferably before (i.e. upstream of) optional combining with further gaseous streams 50, an aliquot of the gaseous stream 30, or an aliquot of the unstabilised naphtha stream 40, is collected with a sampler 300 as a sample 200. The sample is then processed e.g. as explained above in connection with Fig.1 , preferably using the sample treatment and analysis system as shown in Fig. 1.

[0078] 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.

[0079] 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.

[0080] Furthermore, some of the features of the afore-disclosed embodiments of this invention may be used to advantage without the corresponding use of other features. As such, the foregoing description shall be considered as merely illustrative of the principles of the present invention, and not in limitation thereof. Hence, the scope of the invention is only restricted by the appended patent claims.

Claims

CLAIMS1 . A process for producing hydrocarbons having biogenic carbon content, the process comprising: a) providing a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; b) refining the refinery feed in a conversion unit to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) subjecting the conversion effluent to separation in a separation section to obtain at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, and optionally further separating from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) subjecting the gaseous stream to a sweetening treatment to obtain a sweetened gas stream; and e1) collecting as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment or an aliquot of the unstabilised naphtha stream, e2) subjecting the sample to combustion to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably dehydrating the exhaust gas sample, e3) subjecting the exhaust gas sample preferably as dehydrated to a SOx removal treatment to obtain a SOx depleted gas sample, and optionally dehydrating the SOx depleted gas sample, and e4) subjecting at least a portion of the SOx depleted and optionally dehydrated gas sample to a biogenic carbon content determination, preferably using accelerator mass spectrometry (AMS) technique, to obtain the content of biogenic carbon in the gaseous stream or in the unstabilised naphtha stream.

2. The process according to claim 1 , wherein the refinery feed comprises at least one or more of vegetable oil(s), animal fat(s), microbial oil(s), lignocellulose-derived biocrude(s), used lubricating oil(s) having biogenic carbon content, and / or liquefied organic waste having biogenic carbon content, and at least one or more of petroleum feed(s), used lubricating oil(s) having non-biogenic carbon content, and / or liquefied organic waste having non- biogenic carbon content; preferably at least one or more of vegetable oil(s), animal fat(s),microbial oil(s), and / or lignocellulose-derived biocrude(s), and at least one or more petroleum feed(s).

3. The process according to any one of the preceding claims, wherein in step b) the refining includes at least one or more of catalytic hydroprocessing, catalytic cracking, and / or thermal cracking, preferably at least catalytic hydroprocessing, more preferably catalytic hydroprocessing comprising at least catalytic hydrotreatment.

4. The process according to any one of the preceding claims, wherein the separation in step c) may further include removing from the gaseous stream at least part of hydrocarbons having 8 or more carbon atoms, preferably at least part of hydrocarbons having 7 or more carbon atoms, more preferably at least part of hydrocarbons having 6 or more carbon atoms, even more preferably at least part of hydrocarbons having 5 or more carbon atoms, before collecting in step e1) an aliquot of the gaseous stream as a sample.

5. The process according to any one of the preceding claims, wherein after the aliquot of the gaseous stream is collected in step e1), the gaseous stream is combined with one or more further gaseous stream(s) separated from further conversion effluent(s) obtained by refining further refinery feed(s) in further conversion unit(s), wherein the further gaseous stream(s) optionally has / have lower biogenic carbon content than the gaseous stream or essentially no biogenic carbon content, and the gaseous stream is subjected to the sweetening treatment in step d) as combined with said further gaseous stream(s).

6. The process according to any one of the preceding claims, wherein in step d) the sweetening treatment comprises at least absorption, preferably using at least one or more of physical solvent(s) and / or alkanolamine(s).

7. The process according to any one of the preceding claims, wherein in step e1) the aliquots of the gaseous stream and / or of the unstabilised naphtha stream are collected intermittently.

8. The process according to any one of the preceding claims, wherein in step e2) the combustion is conducted in the presence of prevailing air, synthetic air or pure 02, preferably synthetic air or pure 02, most preferably pure 02.

9. The process according to any one of the preceding claims, wherein in step e3) the SOx removal treatment comprises i) selective adsorption of SOx, preferably conducted with at least one or more selectively SOx-adsorbing single metal oxide(s), mixed metal oxides, metal oxide(s) supported on carbonaceous material(s), clay(s), zeolite(s), zeolite-type material(s) and / or porous organic polymers; ii) selective adsorption or absorption of C02,preferably conducted with at least one or more selectively CO2-adsorbing or CO2- absorbing metal organic framework adsorbent(s) (MOFs), organic polymer(s), inorganic adsorbent(s), carbonaceous adsorbent(s), physical solvent(s), amine(s), ionic liquid(s), and / or nanoparticle dispersion(s), followed by recovery of the adsorbed or absorbed CO2; or iii) cryogenic removal of SOx based on the boiling point difference of SOx and CO2.

10. The process according to any one of the preceding claims, wherein the dehydration in step e2) and / or step e3) is conducted using at least one or more synthetic polymers, preferably synthetic ionomers, more preferably sulfonated tetrafluoroethylene-based fluoropolymer-copolymers.

11. The process according to any one of the preceding claims, wherein a portion of the SOx depleted and preferably dehydrated gas sample is subjected to a composition analysis using gas chromatography (GC).

12. The process according to any one of the preceding claims, wherein in step c) at least one or more distillate(s) and a separation bottom are further separated from the degassed hydrocarbon stream, and the biogenic carbon content in all the separated distillate(s) and in the separation bottom are determined, preferably using accelerator mass spectrometry (AMS) technique.

13. A system for producing hydrocarbons having biogenic carbon content, the system comprising: a) at least one or more refinery feed tank(s) configured to receive a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content, or components of the refinery feed; b) a conversion unit in fluid communication with the refinery feed tank(s), and configured to receive and refine the refinery feed to obtain a conversion effluent comprising at least H2S and hydrocarbons, and preferably also carbon oxide(s); c) a separation section in fluid communication with the conversion unit and configured to receive the conversion effluent and to separate therefrom at least a gaseous stream and optionally an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, as well as a degassed hydrocarbon stream, wherein the separation section is optionally further configured to separate from the degassed hydrocarbon stream at least one or more distillate(s) and a separation bottom; d) a sweetening unit in fluid communication with the separation section and configured to receive and sweeten the gaseous stream to obtain a sweetened gas stream; ande) a sample treatment and analysis system comprising: e1) a sampler in communication, preferably in fluid communication, with the separation section and configured to collect as a sample an aliquot of the gaseous stream before subjecting the gaseous stream to the sweetening treatment and / or an aliquot of the unstabilised naphtha stream, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample, e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

14. A sample treatment and analysis system comprising: e1) a sampler configured to collect as a sample an aliquot of a gaseous stream and / or an aliquot of an unstabilised naphtha stream both comprising H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons, e2) a combustion unit in communication, preferably in fluid communication, with the sampler and configured to receive and combust the sample to obtain an exhaust gas sample containing CO2, sulphur oxide(s) (SOx) and H2O, and preferably a first drying unit in communication, preferably in fluid communication, with the combustion unit and configured to receive and dehydrate the exhaust gas sample,e3) a SOx removal unit in communication, preferably in fluid communication, with the combustion unit preferably via the first drying unit, and configured to receive the exhaust gas sample preferably as dehydrated and to remove SOx therefrom to obtain a SOx depleted gas sample, an optional second drying unit in communication, preferably in fluid communication, with the SOx removal unit and configured to receive and dehydrate the SOx depleted gas sample, and preferably a gas chromatography (GO) analyzer in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive a portion of the SOx depleted and preferably dehydrated gas sample and to analyse composition thereof, and e4) a biogenic carbon content analyzer, preferably using accelerator mass spectrometry (AMS) technique, in communication, preferably in fluid communication, with the SOx removal unit optionally via the second drying unit and configured to receive at least a portion of the SOx depleted and optionally dehydrated gas sample and to determine its biogenic carbon content to obtain the content of biogenic carbon in the gaseous stream and / or in the unstabilised naphtha stream.

15. Use of the system for producing hydrocarbons having biogenic carbon content according to claim 13 or of the sample treatment and analysis system of claim 14, in a process for producing hydrocarbons having biogenic and non-biogenic carbon content, preferably in a process according to any one of claims 1 to 12.

16. Use of the sample treatment and analysis system of claim 14 for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process for producing hydrocarbons having biogenic carbon content, wherein the gaseous stream and / or the unstabilised naphtha stream comprise H2S and at least one or more of carbon oxide(s) and / or C1-C3 hydrocarbons and is / are obtainable by separating from a conversion effluent obtained by refining in a conversion unit a refinery feed having biogenic carbon content, non-biogenic carbon content and sulphur content; preferably for creating and / or training a model for estimating biogenic carbon content in a gaseous stream and / or in an unstabilised naphtha stream in a process according to any one of claims 1 to 12.

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