Integrated slurry hydroprocessing and paraffinic froth treatment methods

Abstract

Systems and methods are provided for integrating paraffinic froth treatment of oil sands for bitumen production with subsequent slurry hydroprocessing for formation of a heavy hydrocarbon product that can satisfy transport specifications, such as pipeline transport specifications. The integrated systems and methods can allow for increased retention of hydrocarbons, such as asphaltenes, in the bitumen and / or in the resulting heavy hydrocarbon product. This increase in hydrocarbon retention is achieved, at least in part, by modifying the severity of the paraffinic froth treatment to form the bitumen.

Description

INTEGRATED SLURRY HYDROPROCESSING AND PARAFFINIC FROTH TREATMENT METHODSHELD OF THE INVENTION

[0001] Systems and methods are provided for upgrading of heavy hydrocarbons generated by paraffinic froth treatment of oil sands.BACKGROUND OF THE INVENTION

[0002] Oil sands are a type of non-traditional petroleum source that remain challenging to fully exploit. Among the components present in oil sands are conventional petroleum components, bitumen, and non-petroleum solids. Crude bitumen includes hydrocarbon components such as asphaltenes and maltenes. Due to the complex nature of oil sands, substantial processing can be required at an extraction site just to create fractions that are suitable for transport. Moreover, oil sands extraction sites are also often in geographically remote locations, which can substantially increase the construction and maintenance costs for any processing equipment that is used at the oil sands extraction site.

[0003] Froth treatments are commonly employed for extracting hydrocarbon components from mined oil sands to facilitate transport and further processing thereof. After mining of oil sands, the oil sands are initially washed with water to remove a portion of the solids. This action results in a “froth” mixture typically including 50 wt% to 70 wt% bitumen and other hydrocarbon components, with the balance of the froth corresponding to water and solids. In order to separate the bitumen and other hydrocarbon components from the water and solids in the froth, a froth treatment can be performed. During a froth treatment, a light solvent is added to the froth in a sufficient amount to cause precipitation of at least a portion of the asphaltenes and a phase separation. Examples of suitable light solvents are paraffin solvents (referred to herein as a paraffinic froth treatment) and naphtha solvents (referred to herein as a naphthenic froth treatment). The phase separation results in a first phase that primarily contains bitumen and the light solvent and one or more secondary phases having relatively high contents of water and particles.

[0004] After the froth treatment, the content of the phase primarily containing bitumen and light solvent can vary depending on the type of froth treatment performed. In addition to the bitumen and light solvent, variable amounts of particles and water may also be present due to incomplete phase separation. Conventional naphthenic froth treatment conditions typically produce a bitumen and light solvent phase that also contains approximately 1.0 wt% to 2.4 wt% water and particulate solids (particles). This content of water and / or solids is typically too high for pipeline transport or subsequent processing, so additional particle removal may be conducted priorto transport of a bitumen formed from naphtha froth treatment. Paraffinic froth treatments, in contrast, typically produce a bitumen and light solvent phase that may contain 0.03 wt% or less of particulate solids (particles) and a combined content of water and particulate solids of 0.2 wt% or less. A paraffinic froth treatment therefore may afford a content of particulate solids that is up to two orders of magnitude lower than in a naphthenic froth treatment. Paraffinic froth treatments, however, also may reject 40 wt% or more of the asphaltenes initially present in the bitumen. This represents a substantial loss of hydrocarbons from the bitumen, thereby decreasing the economic value of the oil sands. Since the asphaltenes are rejected into the one or more of secondary phases containing solids and water, further recovery of the asphaltenes in an economically viable manner may be difficult.

[0005] Although paraffinic froth treatments can be effective for reducing the water and solids content of bitumen to a desired level, some additional preparation is usually still required to form a bitumen that is suitable for pipeline transport. For bitumen obtained from a paraffinic froth treatment, one strategy for preparing the bitumen for pipeline transport is addition of a low- viscosity diluent to the bitumen. Naphtha fractions are an example of a suitable diluent. However, the diluent can correspond to 30 wt% or more of the diluted bitumen that is to be transported. Thus, a substantial amount of naphtha has to be transported to and from the extraction site, thereby further increasing production costs. The large volume of diluent also means that the effective bitumen capacity of the pipeline is reduced. Additionally, the resulting bitumen from the paraffinic froth treatment has a dumbbell boiling range distribution due to the co-presence of the naphtha and high- boiling vacuum resid, thereby rendering this feed challenging for most refineries to process. Due to the relatively low asphaltene content following paraffinic froth treatment, production of asphalt products from the feed is usually not feasible either.

[0006] U.S. Patent 9,200,206 describes performing a froth treatment on bitumen using a polar organic solvent. A weight ratio of solvent to bitumen after addition of the solvent can be between 1 .4 to 2.2. However, this reference does not resolve the foregoing issues.

[0007] Accordingly, improved systems and methods for extracting bitumen from oil sands and preparing the bitumen for pipeline transport would be highly desirable. The improved systems and methods would preferably provide one or more of: reduced or minimized dependence on external process streams, reduced or minimized capital equipment costs, and reduced or minimized creation of fractions that require an alternate transport or processing method.SUMMARY OF THE INVENTION

[0008] In various aspects, a method for upgrading oil sands to form a processed heavy hydrocarbon product is provided. The methods comprise: exposing oil sands to a water extraction process to form a froth, the oil sands comprising particles and asphaltenes; adding a paraffinic froth solvent to the froth under froth treatment conditions to form a bitumen comprising 0.05 wt% or more particles, based upon total mass of the bitumen; wherein about 80 wt% or more of the asphaltenes from the oil sands are retained in the bitumen; and exposing at least a portion of the bitumen obtained from the froth treatment conditions to slurry hydroprocessing conditions in a slurry hydroprocessing reactor in the presence of the particles to form a light ends fraction, a slurry hydroprocessing effluent, and a pitch fraction, the slurry hydroprocessing conditions affording 90% conversion or less of the bitumen to 566°C.

[0009] These and other features and attributes of the disclosed systems and / or methods of the present disclosure and their advantageous applications and / or uses will be apparent from the detailed description which follows.BRIEF DESCRIPTION OF THE DRAWINGS

[0010] The following figures are included to illustrate certain aspects of the present disclosure, and should not be viewed as exclusive embodiments. The subject matter disclosed is capable of considerable modifications, alterations, combinations, and equivalents in form and function, as will occur to one having ordinary skill in the art and having the benefit of this disclosure.

[0011] To assist those of ordinary skill in the relevant art in making and using the subject matter hereof, reference is made to the appended drawings, wherein:

[0012] FIG. 1 is a block diagram of an illustrative slurry hydroprocessing reactor system.

[0013] FIG. 2A is a block diagram of a first configuration for integrating a paraffinic froth treatment process with a slurry hydroprocessing process according to the present disclosure. FIG. 2B is a block diagram of a second configuration for integrating a paraffinic froth treatment process with a slurry hydroprocessing process according to the present disclosure.

[0014] FIG. 3 is a block diagram of a system for performing a staged paraffinic froth treatment.

[0015] FIG. 4 is a block diagram of an integrated system and process having a staged paraffinic froth treatment stage and a slurry hydroprocessing stage.

[0016] FIG. 5 is a graph of toluene-insoluble coke formation obtained during slurry hydroprocessing as function of catalyst or oil sands particle loading.

[0017] FIG. 6 is a graph of product composition obtained during slurry hydroprocessing as function of catalyst loading.

[0018] FIG. 7 is a graph of coke formation obtained during slurry hydroprocessing as function of oil sands particle loading in lieu of a Mo catalyst.

[0019] FIG. 8 is a graph of particle settling rate as a function of solvent to bitumen ratio during paraffinic froth treatment under various single-stage and two-stage separation conditions.

[0020] FIG. 9 is a graph of asphaltenes content as function of solvent to bitumen ratio during an illustrative paraffinic froth treatment.

[0021] FIG. 10 is a graph of settling rate as function of asphaltenes content during an illustrative paraffinic froth treatment.

[0022] FIG. 11 is a graph of volumetric throughput for single-stage and multi-stage paraffinic froth treatments as a function of bitumen recovery.DETAILED DESCRIPTION OF THE INVENTION

[0023] Systems and methods are provided for upgrading of heavy hydrocarbons generated by paraffinic froth treatment of oil sands.

[0024] In various aspects, systems and methods are provided for integrating paraffinic froth treatment of oil sands for bitumen production with subsequent slurry hydroprocessing of the bitumen for formation of a heavy hydrocarbon product that can satisfy transport specifications, such as pipeline transport specifications. The integrated systems and methods can allow for increased retention of hydrocarbons in the bitumen (e. ., less rejection of asphaltenes) and / or in the resulting heavy hydrocarbon product. The increased hydrocarbon retention is achieved, at least in part, by modifying the severity or other conditions of the paraffinic froth treatment to form the bitumen with higher recovery of asphaltenes.

[0025] Conventionally, the severity of a paraffinic froth treatment is selected to reduce or minimize the particle content of the bitumen. However, the amount of particle removal achieved during conventional paraffinic froth treatments is beyond the level required to meet a typical transport specification. Instead, the level of particle removal is often selected to sufficiently reduce the particle content of the bitumen so that the bitumen is suitable for processing in various types of conventional refinery processes, such as desalters and fixed bed reactors. Desalters typically can perform some limited particle removal, but the higher the particle content, the longer the settling time that is required in the desalter settling tank, as increased amounts of solids tend to stabilize an emulsion layer formed between oil and an aqueous fluid. Thus, reducing the particle content of the bitumen feed, such as during a conventional paraffinic froth treatment, can improve the efficiency of a subsequent desalting process. Additionally, reducing the particle content of the bitumen to 0.03 wt% or less can allow the bitumen to be processed in fixed bed processing unitswhile avoiding fouling of the fixed bed and / or avoiding other various conditions that could result in significantly shorter run lengths. Unfortunately, reducing the particle content to this low level also results in substantial rejection of asphaltenes in the form of precipitated asphaltenes that are difficult to recover and further process. In addition, excessive removal of asphaltenes can also render the resulting bitumen unsuitable for production of asphalt, for instance.

[0026] It has been discovered that an integrated process for treating bitumen through sequential paraffinic froth treatment and slurry hydroprocessing can allow for retention of increased amounts of asphaltenes in the bitumen while still keeping the bitumen (or a hydrocarbon product produced therefrom) suitable for pipeline transport and further refinery processing. Instead of minimizing the particle content of the bitumen during the paraffinic froth treatment, as performed conventionally, the conditions of the paraffinic froth treatment can be selected to form bitumen with an intermediate reduction in particle content while retaining an increased amount of asphaltenes (e.g., fewer asphaltenes precipitate in a non-recoverable form). The particle reduction during the paraffinic froth treatment can be selected to be sufficient for transport of the bitumen from the froth treatment process to the slurry hydroprocessing process. The slurry hydroprocessing process can then be used to produce an upgraded bitumen (upgraded heavy hydrocarbon product) while further reducing the particle content of the upgraded bitumen. The further reduction in particle content is achieved based on segregation of particles into an unconverted pitch (or bottoms) fraction generated during slurry hydroprocessing. By performing slurry hydroprocessing at a desirable level of conversion relative to 566°C, the amount of unconverted bottoms can be reduced or minimized while still removing substantially all or at least a majority of the particles from the converted effluent created during slurry hydroprocessing (e.g., the upgraded bitumen). As used herein, the phrase “conversion relative to” a specified temperature means the percentage difference in the weight fraction of feed having a boiling point above the specified temperature relative to the weight fraction of product having a boiling point above the specified temperature. For example, the conversion relative to 566°C may be determined by the expression 100*(weight fraction of feed having a boiling point above 566°C- weight fraction of product having a boiling point above 566°C) / weight fraction of feed having a boiling point above 566°C. The specified temperature (e.g., 566°C) represents the cut point of the distillation separating feed or product from bottoms. A cut point of 566°C is convenient for slurry hydrocracking, since slurry hydrocracking reactions are usually designed to convert feed at least above this temperature.

[0027] While separation of the unconverted bottoms in the disclosure herein represents some loss in yield (relative to direct conversion of the bitumen without slurry hydroprocessing), this loss is offset by the retention of a substantially higher percentage of asphaltenes in the bitumen passedto the slurry hydroprocessing process environment. Additionally, a portion of the asphaltenes from the crude bitumen can remain in the converted effluent (z.<?. , the upgraded bitumen) obtained from the slurry hydroprocessing process. This feature can allow the resulting upgraded bitumen to have a higher capability for production of asphalt, optionally after some additional processing. Alternately, some bitumen with a higher aspheltene content could bypass the upgrading units (slurry hydroprocessing process reactor) and be used directly to produce better quality asphalt.

[0028] In addition to creating upgraded bitumen, modifying the paraffinic froth treatment conditions to retain additional asphaltenes and particles can have other potential benefits during slurry hydroprocessing. The particles extracted with the bitumen may contain transition metal or rare earth elements that may exhibit catalytic activity during slurry hydroprocessing. Thus, the particles retained at an intermediate level in the bitumen following the paraffinic froth treatment may act as supplemental catalyst (or possibly even the only catalyst) within the slurry hydroprocessing reactor. The unexpected additional catalytic activity provided by the retained particles may reduce or minimize the amount of coke formed within the slurry hydroprocessing process environment. Additionally or alternately, the unexpected additional catalytic activity can allow for a reduction in the amount of a slurry hydroprocessing catalyst that is separately added to the slurry hydroprocessing environment.

[0029] In various aspects, the conditions for the paraffinic froth treatment can be selected to retain an intermediate amount of the particles, so that the bitumen contains 0.05 wt% or more of particles, or 0.1 wt% or more particles, or 0.5 wt% or more particles, or 1 wt% or more particles, such as 0.05 wt% to 0.5 wt% particles, or 0.1 wt% to 0.5 wt% particles, or 0.1 wt% to 10 wt% particles, or 0.1 wt% to 5 wt% particles, or 0.05 wt% to 10 wt% particles, each as measured relative to a total mass of the bitumen. Total mass of the bitumen represents a combined mass of the hydrocarbon components (e.g., asphaltenes) and the particles. Following the paraffinic froth treatment, the bitumen can then optionally undergo one or more boiling point separations e.g. , one or more distillations, flash separations, or fractionations) and / or solvent separations e.g., solvent deasphalting) to form one or more lower boiling fractions and a vacuum bottoms fraction and / or rock fraction containing substantially all of the particles not initially separated from the crude bitumen during the paraffinic froth treatment. The vacuum bottoms fraction can correspond to up to 50 wt% of the bitumen obtained from the paraffinic froth treatment. The lower boiling fractions can include one or more of a naphtha fraction, a distillate fraction, an atmospheric gas oil fraction, a vacuum gas oil fraction, or any combination thereof. By concentrating the particles in the vacuum bottoms fraction, the particle content in the vacuum bottoms fraction after fractionation can be higher than in the bitumen obtained from the paraffinic froth treatment. In non-limiting examples,the particle content of the vacuum bottoms fraction may be higher than 0.05 wt% and range from 0.1 wt% or more particles, or 0.5 wt% or more particles, or 1 wt% or more particles, such as 0.1 wt% to 0.5 wt% particles, or 0.1 wt% to 10 wt% particles, or 0.1 wt% to 5 wt% particles, or 0.1 wt% to 1 wt% particles, based on a total mass of the vacuum bottoms fraction. Optionally, if only an atmospheric separator is used, the lower boiling fractions can correspond to one or more of a naphtha fraction, a distillate fraction, or any combination thereof, which are separated from an atmospheric bottoms fraction. The particle content in the atmospheric bottom fraction may be similar to those of the vacuum bottoms fraction. Still another alternative can be to include a solvent deasphalting stage in addition to and / or in place of any distillation stage(s). In such aspects, the particles in the bitumen can be concentrated in the deasphalter bottoms or rock fraction. The particle content in the deasphalter bottoms or rock fraction may be similar to those of the vacuum bottoms fraction.

[0030] The vacuum bottoms fraction (or atmospheric bottoms fraction, or deasphalter bottoms) with the concentrated particle content can then be passed into a slurry hydroprocessing stage, such as one or more slurry hydroprocessing reactors. In non-limiting examples, the atmospheric bottoms fraction or vacuum bottoms fraction may comprise 343°C+ compounds. The particles can serve as some or all of the catalyst within the one or more slurry hydroprocessing reactors. The slurry hydroprocessing can generate a light ends fraction, a slurry hydroprocessing effluent corresponding to a desired product (e.g., an upgraded bitumen), and a pitch fraction or similar unconverted fraction. Substantially all of the particles in the vacuum bottoms fraction (or atmospheric bottoms fraction, or deasphalter bottoms) can be removed from the upgraded bitumen by becoming concentrated in the pitch fraction generated during slurry hydroprocessing. The pitch fraction may be removed from the slurry hydroprocessing reactor as a purge stream.

[0031] In some aspects, a combination of a paraffinic froth treatment and slurry hydroprocessing can be used to prepare a heavy hydrocarbon feed suitable for transport, such as pipeline transport. Preparing heavy hydrocarbon feeds suitable for pipeline transport often involves achieving target values for three separate properties. First, the viscosity of the heavy hydrocarbon feed after processing needs to be suitable for pipeline transport. This feature can correspond to, for example, having a kinematic viscosity of 350 cSt or less at 100°C (KvlOO) by ASTM D445. Second, the density of the heavy hydrocarbon feed after processing needs to be suitable for pipeline transport. This feature can correspond to, for example, having an API Gravity of 19° or more by ASTM D287. Third, the particle and water contents of the heavy hydrocarbon feed after processing need to be sufficiently low. In non-limiting examples, a sufficiently water and sediment (particle) content may be about 1 vol% or below, or about 0.5 vol% or below, orabout 0.25 vol% or below, or about 0.1 vol% or below. Individually, a particle content in the heavy hydrocarbon feed (upgraded bitumen) suitable for transport may be about 0.5 wt% or below relative to a total mass of the upgraded bitumen. The amount of water in the heavy hydrocarbon feed may be selected such that subsequent processing operations are not overly impacted by the presence of excess water.

[0032] Conventional processes may utilize substantial volumes of a transport diluent, up to 30 vol% or more, to satisfy pipeline transport requirements. In various aspects, the amount of diluent that is needed to satisfy kinematic viscosity and / or density requirements in the disclosure herein can be reduced or eliminated by using slurry hydroprocessing to treat at least a portion of the bitumen, such as a vacuum bottoms fraction of the bitumen. By exposing the bottoms fraction of the bitumen to slurry hydroprocessing conditions, a portion of the vacuum bottoms fraction can be converted to lower boiling components, whose formation may reduce the kinematic viscosity and density of the converted portion of the bitumen. The converted portion can then be recombined with any portions of the bitumen that were not exposed to the slurry hydroprocessing conditions to form an upgraded bitumen product (or the converted portion of the bitumen may define the entirety of the converted portion of the bitumen). It is noted that in the above aspect, the pitch fraction or unconverted bottoms from the slurry hydroprocessing reaction is not included in the upgraded bitumen. Forming an upgraded bitumen without including the slurry hydroprocessing pitch, or while including only a reduced or minimized portion of the pitch, provides a further decrease in the density and kinematic viscosity of the upgraded bitumen. Additionally, avoiding the inclusion of pitch from slurry hydroprocessing can reduce or minimize the risk of toluene insolubles formation due to incompatibility. Based on the various decreases in the density and kinematic viscosity, the amount of diluent required to facilitate transport of the upgraded bitumen can be reduced or minimized, such as possibly needing no additional transport diluent.

[0033] Based on the above, integration of a paraffinic froth treatment with slurry hydroprocessing can provide various and unexpected synergies when used for upgrading of bitumen derived from oil sands. Because slurry hydroprocessing provides a mechanism for concentrating particles in the slurry hydroprocessing pitch, an integrated paraffinic froth treatment can be operated at lower severity to allow for increased retention of asphaltenes within the bitumen prior to slurry hydroprocessing, thereby increasing the retained hydrocarbon content. This lower severity can be achieved, at least in part, by reducing or minimizing the solvent to bitumen ratio during the paraffinic froth treatment. Reducing the amount of solvent can decrease operating costs and / or increase the capacity of the paraffinic froth treatment for processing crude bitumen within oil sands. The resulting increased particle content in the bitumen obtained from the paraffinic frothtreatment can be beneficial for reducing the amount of coke generated during slurry hydroprocessing and / or reducing or minimizing the amount of additional catalyst needed to suppress coke formation during slurry hydroprocessing. Additionally, the amount of diluent required for transport of the upgraded bitumen can be reduced or minimized.

[0034] As still another benefit, slurry hydroprocessing can provide additional advantages over alternative processes by utilizing a bitumen fraction having an increased asphaltene content as the feed. In many alternative processes, such as coking, asphaltenes within a feed are substantially converted to low-value coke. By contrast, slurry hydroprocessing can upgrade asphaltenes within a bitumen feed to form vacuum gas oil boiling range products, which have a substantially higher value than coke. Thus, by integrating a paraffinic froth treatment with slurry hydroprocessing, a synergistic yield improvement can be realized by retaining additional asphaltenes in the bitumen following the paraffinic froth treatment.

[0035] In some aspects, systems and methods are also provided for performing a paraffinic froth treatment as a staged process (multi-stage) rather than as a single-stage process. In such aspects, a staged paraffinic froth treatment process can be used to accomplish one or more of improving particle removal; reducing the amount of paraffinic solvent; reducing loss of asphaltenes; enhancing overall hydrocarbon recovery; and / or increasing throughput for the paraffinic froth treatment process. For example, in at least one embodiment, a staged paraffinic froth treatment may afford increased particle settling rates in combination with increased asphaltene retention within a bitumen prior to slurry hydroprocessing.DEFINITIONS

[0036] As used herein, unless otherwise specified, “conversion” of a feedstock or other input stream is defined as conversion relative to a temperature of 524°C (975°F). Per-pass conversion (at a specified temperature) refers to the amount of conversion that occurs during a single pass through a reactor / stage / reaction system. It is noted that recirculation streams ( / .<?. , streams having substantially the same composition as the liquid in the reactor) are included in the calculation of per-pass conversion. Net or overall conversion refers to the net products from the reactor I stage / reaction system, so that any recycle streams are included in the calculation of the net or overall conversion. It is noted that in all aspects described herein, the amount of conversion at 524°C is lower than the corresponding conversion at 566°C.

[0037] As used herein, the “combined feed ratio” (or CFR) is defined as a ratio corresponding to (mass flow rate of fresh feed + mass flow rate of recycle stream) / (mass flow rate of fresh feed). Based on this definition, the combined feed ratio when no recycle is used is 1.0. When recycle ispresent, the relative mass flow rate of the recycle stream as a percentage of the fresh feed can be added to 1.0 to provide the combined feed ratio. Thus, when the mass flow rate of the recycle stream is 10% of the mass flow rate of the fresh feed, the CFR is 1.1. When the mass flow rate of the recycle stream is 50% of the mass flow rate of the fresh feed, the CFR is 1.5. When the mass flow rate of the recycle stream is 100% of the mass flow rate of the fresh feed, the CFR is 2.0.

[0038] As used herein, when describing the amount of a fresh feed stream, recirculation stream, recycle stream, or other stream, the mass flow rate of the stream may also be referred to as a “weight” of the stream.

[0039] As used herein, the Liquid Hourly Space Velocity (LHSV) for a feed or a portion of a feed to a slurry hydroprocessing reactor is defined as the volume of feed per hour relative to the volume of the reactor.

[0040] As used herein, a “Cx” hydrocarbon refers to a hydrocarbon compound that includes “x” number of carbons in the compound. A stream containing “Cx- Cy” hydrocarbons refers to a stream composed of one or more hydrocarbon compounds that includes at least “x” carbons and no more than “y” carbons in the compound. It is noted that a stream comprising Cx- Cyhydrocarbons may also include other types of hydrocarbons, unless otherwise specified. The hydrocarbons may be linear, branched, cyclic, aromatic, or any combination thereof.

[0041] As used herein, “Tx” refers to the temperature at which a weight fraction “x” of a sample can be boiled or distilled. For example, if 40 wt% of a sample has a boiling point of 343°C or less, the sample can be described as having a T40 distillation point of 343°C. In this discussion, boiling points can be determined by a convenient method based on the boiling range of the sample. The boiling point may be determined according to ASTM D2887, or for heavier samples ASTM D7169.

[0042] As used herein, references to “fresh feed” with respect to a hydroconversion stage correspond to a feedstock that has not been previously passed through the hydroconversion stage. This is in contrast to recycled feed portions that are formed by fractionation and / or other separation of the products from the hydroconversion stage.

[0043] In various aspects of the present disclosure, reference may be made to one or more types of fractions generated during distillation of a petroleum feedstock, intermediate product, and / or product. Such fractions may include naphtha fractions, distillate fuel fractions, and vacuum gas oil fractions. Each of these types of fractions can be defined based on a boiling range, such as a boiling range that includes at least 90 wt% of the fraction, or at least 95 wt% of the fraction. For example, for naphtha fractions, at least 90 wt% of the fraction, or at least 95 wt% of the fraction, can have a boiling point in the range of 85°F (29°C) to 35O°F (177°C). It is noted that 29°C roughlycorresponds to the boiling point of isopentane, a Cs hydrocarbon. For a distillate fuel fraction, at least 90 wt% of the fraction, or at least 95 wt% of the fraction, can have a boiling point in the range of 350°F (177°C) to 650°F (343°C). For a vacuum gas oil fraction, at least 90 wt% of the fraction, or at least 95 wt% of the fraction, can have a boiling point in the range of 650°F (343 °C) to 1050°F (566°C). Fractions boiling below the naphtha range can sometimes be referred to as light ends. Fractions boiling above the vacuum gas oil range can be referred to as vacuum resid fractions or pitch fractions.

[0044] Another option for specifying various types of boiling ranges can be based on a combination of T5 (or T10) and T95 (or T90) distillation points. For example, in some aspects, having at least 90 wt% of a fraction boil in the naphtha boiling range can correspond to having a T5 distillation point of 29°C or more and a T95 distillation point of 177°C or less. In some aspects, having at least 90 wt% of a fraction boil in the distillate boiling range can correspond to having a T5 distillation point of 177°C or more and a T95 distillation point of 343°C or less. In some aspects, having at least 90 wt% of a fraction boil in the vacuum gas oil range can correspond to having a T5 distillation point of 343 °C or more and a T95 distillation point of 566°C or less.

[0045] In this discussion, the boiling range of components in a feed, intermediate product, and / or final product may alternately be described based on describing a weight percentage of components that boil within a defined range. The defined range can correspond to a range with an upper bound, such as components that boil at less than 177°C (referred to as 177°C-); a range with a lower bound, such as components that boil at greater than 566°C (referred to as 566°C+); or a range with both an upper bound and a lower bound, such as 343°C - 566°C.Feedstocks - Paraffinic Froth Treatment of Feeds with Increased Particle Content

[0046] For crude oils derived from conventional extraction sites, the particle content of the crude oil is typically low. However, an increasing proportion of crude oil production corresponds to non-traditional crudes, such as crude oils derived from oil sands. Initial extraction of non- traditional crudes can present some additional challenges. For example, during mining or extraction of oil sands, a large percentage of non-petroleum material (such as sand) may be present in the raw product, commonly in particle form.

[0047] The particle content and / or content of other non-petroleum materials present in oil sands can be quite large, possibly corresponding to 30 wt% or more of the product. An initial reduction in the particle content can be performed by first extracting the raw product with water. The Clark hot water extraction process (~80-85°C water) is an example of an extraction process for oil sands. Other heated water extraction processes may also be suitable. Air is typically bubbled through the water to assist in separating the bitumen from the non-petroleum material. This actionmay remove a large proportion of the solid, non-petroleum material in the raw product. However, smaller particles of non-petroleum particulate solids may remain with the oil phase at the top of the mixture. This top oil phase is sometimes referred to as a froth. The particles in the froth can still correspond to 5.0 wt% or more of the froth, or 10 wt% or more, such as up to 20 wt% or possibly still higher. Additionally, the combined particle and water content of the froth can correspond to 40 wt% or more of the froth.

[0048] Separation of the smaller non-petroleum particulate solids can be achieved by adding a froth solvent to the froth. This action may be referred to as a froth treatment. Examples of froth treatments include paraffinic froth treatment (PFT) and naphthenic froth treatment (NFT). For paraffinic froth treatments, typical froth solvents include isopentane, pentane, and other light paraffins (such as Cs - Cs paraffins) that are liquids at room temperature. Other solvents such as C3 - Cio alkanes may also be suitable for use as a froth solvent for forming an asphaltene-depleted crude, depending on the conditions during the froth treatment. For naphthenic froth treatment, a mixture of naphtha boiling range compounds can be used, where the mixture includes aromatics, naphthenes, and optionally paraffins. It is noted that the froth solvents for paraffinic froth treatment roughly correspond to naphtha boiling range compounds as well, so that the difference between the froth solvents for PFT and NFT is based on compound class (aromatic, naphthene, paraffin) rather than boiling range.

[0049] During a froth treatment, adding the froth solvent to the froth results in a two-phase mixture, with the crude and the froth solvent forming one of the phases. The smaller particulate solids of non-petroleum material are “rejected” from the oil phase and join the aqueous phase. The crude oil and solvent phase can then be separated from the aqueous phase. During conventional paraffinic froth treatments, after separation from the aqueous phase, the resulting bitumen can have a combined water and particle content of up to 0.15 wt%. By contrast, when performing a paraffinic froth treatment as described herein to provide an increased retention of particles in the bitumen, the combined water and particle content of the resulting bitumen can be 1.0 wt% or more, or 3.0 wt% or more, or 5 wt% or more, such as up to 10 wt%, or possibly still higher. The particle content of the resulting bitumen can be about 0.05 wt% or more, or 0.1 wt% or more, or 0.5 wt% or more, such as 0.05 wt% to 0.5 wt%, or 0.1 wt% to 5.0 wt%, or 0.1 wt% to 3.0 wt%, or 0.1 wt% to 10 wt%, or 0.1 wt% to 5 wt%, or 0.5 wt% to 5.0 wt%, or 0.5 wt% to 3.0 wt%, each based on a total mass of the bitumen (combined mass of the bitumen and particles).

[0050] When a paraffinic froth treatment is performed under conventional conditions, the paraffinic froth treatment can also impact the amount of asphaltenes that are retained in the bitumen. When a paraffinic froth solvent is added to the mixture of raw product and water, about30 and 60 percent of the asphaltenes in the crude oil may be “rejected” and lost to the water phase along with the smaller non-petroleum particulate solids. As a result, the bitumen that is separated out from the non-petroleum material after a paraffinic froth treatment corresponds to an asphaltene- depleted crude oil. In other words, prior to the paraffinic froth treatment, the crude oil present in the raw product and water mixture contained an initial level of asphaltenes. By using the paraffinic froth treatment to remove a portion of the particles, the asphaltene content of the crude may be reduced or depleted by at least about 30 wt%, such as at least about 40 wt%, or at least about 45 wt%. That is, the resulting asphaltene-depleted crude (asphaltene-depleted bitumen) may have about 30 wt% less asphaltenes than the corresponding raw crude, such as at least about 40 wt% less, or at least about 45 wt% less, when the paraffinic froth treatment is performed conventionally. Conventionally, the paraffinic froth treatment may reduce or deplete the asphaltenes in the crude bitumen by about 60 wt% or less, such as about 55 wt% or less, or about 50 wt% or less. The amount of asphaltenes that are removed or depleted can depend on a variety of factors. Possible factors that can influence the amount of asphaltene depletion include the nature of the paraffinic froth solvent, the amount of paraffinic froth solvent relative to the amount of bitumen, the temperature during the paraffinic froth treatment process, and the nature of the raw bitumen being exposed to the paraffinic froth treatment.

[0051] Modifying the paraffinic froth treatment conditions according to the disclosure herein to retain a higher percentage of particles in the bitumen can provide a variety of potential benefits. Example modifications that may prove beneficial in this respect include, but are not limited to, increasing the temperature e.g., from 70°C to 90°C) and increasing the number of processing stages {e.g. , two-stage processing instead of single-stage processing). In some aspects, the increased amount of particles can serve as additional catalyst during slurry hydroprocessing. Additionally or alternately, the treatment conditions that allow for retention of increased particles in the bitumen also result in retaining an increased amount of asphaltenes following the paraffinic froth treatment. The paraffinic froth treatment may be staged as two or more frothing stages to accomplish the foregoing.

[0052] Various possible modifications can be used to allow a paraffinic froth treatment to retain additional particles in the bitumen. Conventional froth treatment conditions can include mixing the froth with solvent under conditions including a solvent to froth weight ratio of 1.4:1 to 2.2:1, on a weight basis, and at a mixing temperature of 60°C to 80°C. To create a bitumen with an increased content of particles according to the disclosure herein, the weight ratio of solvent to froth can be reduced and / or the mixing temperature can be increased. For example, the mixing temperature for the froth and solvent can be 85°C or more, such as 85°C to 100°C. Additionallyor alternately, the solvent to froth weight ratio can be reduced to 1.3 or less, such as a ratio of 1.0:1 to 1.3: 1. The froth weight may correspond to the bitumen weight.Feedstocks

[0053] In various aspects, the feed corresponds to a heavy hydrocarbon feed formed by performing a modified paraffinic froth treatment on oil sands to obtain a bitumen. It is understood that the bitumen obtained from the paraffinic froth treatment may be a diluted bitumen that includes a portion of the paraffinic solvent used during the paraffinic froth treatment. In this discussion, references to the properties of a bitumen refer to the properties of the bitumen in the absence of any diluent from the paraffinic froth treatment. The properties of the combination of bitumen and diluent will be referred to as properties of a diluted bitumen, also referred to as “dilbit”.

[0054] As used herein, a heavy hydrocarbon feed corresponds to a feed where a substantial portion of the feed has a boiling point of 1050°F (566°C) or more, or 1100°F (593°C) or more. In some aspects, 50 wt% or more of a heavy hydrocarbon feed (i.e., a bitumen) can have a boiling point of 566°C or more, or 60 wt% or more, or 70 wt% or more, or 80 wt% or more, such as up to substantially all of the heavy hydrocarbon feed corresponding to components having a boiling point of 566°C or more. In some aspects, 50 wt% or more of a heavy hydrocarbon feed can have a boiling point of 593°C or more, or 60 wt% or more, or 70 wt% or more, or 80 wt% or more, such as up to substantially all of the heavy hydrocarbon feed corresponding to components with a boiling point of 593 °C or more. In this discussion, boiling points can be determined by a convenient method, such as ASTM D2887, ASTM D7169, or another suitable standard method.

[0055] Density, or weight per volume, of the heavy hydrocarbon feed can be determined according to ASTM D287 - 92 (2006) Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), and is provided in terms of API gravity. In general, the higher the API gravity, the less dense the oil. API gravity of the bitumen or heavy hydrocarbon feed herein can be 15° or less, or 10° or less, or 5° or less.

[0056] Heavy hydrocarbon feeds can be high in metals. For example, the heavy hydrocarbon feed can be high in total nickel, vanadium and iron contents. In one embodiment, the heavy hydrocarbon feed (bitumen) may contain at least 0.00005 grams of Ni / V / Fe (50 ppm) or at least 0.0002 grams of Ni / V / Fe (200 ppm) per gram of heavy oil, on a total elemental basis of nickel, vanadium and iron. In other aspects, the heavy hydrocarbon feed may contain at least about 500 wppm of nickel, vanadium, and iron, such as at least about 1000 wppm. The metal content in the hydrocarbon feeds my allow one to forego adding a separate catalyst during slurry hydroprocessing according to various aspects of the disclosure herein. All or a portion of the metal content may bepresent upon particles retained in the heavy hydrocarbon feed following a paraffinic froth treatment according to the disclosure herein.

[0057] Heteroatoms such as nitrogen and sulfur are typically found in heavy hydrocarbon feeds, often in organically -bound form. Nitrogen content can range from about 0.1 wt% to about 3.0 wt% elemental nitrogen, or 1.0 wt% to 3.0 wt%, or 0.1 wt% to 1.0 wt%, based on total weight of the heavy hydrocarbon feed. The nitrogen containing compounds can be present as basic or non-basic nitrogen species. Examples of basic nitrogen species include quinolines and substituted quinolines. Examples of non-basic nitrogen species include carbazoles and substituted carbazoles.

[0058] The present disclosure may be particularly suited to treating heavy hydrocarbon feeds containing at least 0.1 wt% sulfur, based on total weight of the heavy hydrocarbon feed. Generally, the sulfur content can range from 0.1 wt% to 10 wt% elemental sulfur, or 1.0 wt% to 10 wt%, or 0. 1 wt% to 5.0 wt%, based on total weight of the heavy hydrocarbon feed. Sulfur will usually be present as organically bound sulfur. Examples of such sulfur compounds include the class of heterocyclic sulfur compounds such as thiophenes, tetrahydrothiophenes, benzothiophenes and their higher homologs and analogs. Other organically bound sulfur compounds include aliphatic, naphthenic, and aromatic mercaptans, sulfides, and di- and polysulfides.

[0059] Heavy hydrocarbon feeds may be high in asphaltenes, but the paraffinic froth treatment may decrease the level of asphaltenes according to the disclosure herein. In some aspects, the heavy hydrocarbon feed can contain 5.0 wt% or more of asphaltenes, or 10 wt% or more, or 15 wt% or more, such as up to 30 wt%, or possibly still higher. Following the paraffinic froth treatment, the amount of asphaltenes in the heavy hydrocarbon feed can be 5.0 wt% to 20 wt%, or 5.0 wt% to 15 wt%, or 10 wt% to 20 wt%, or 15 wt% to 18 wt%. In the disclosure herein, the resulting bitumen may retain at least about 70% of the asphaltenes from the heavy hydrocarbon feed, or at least about 75% of the asphaltenes from the heavy hydrocarbon feed, or at least about 80% of the asphaltenes from the heavy hydrocarbon feed, or at least about 85% of the asphaltenes from the heavy hydrocarbon feed, or at least about 90% of the asphaltenes from the heavy hydrocarbon feed, or at least about 95% of the asphaltenes from the heavy hydrocarbon feed.

[0060] Still another method for characterizing a heavy hydrocarbon feed is based on the Conradson carbon residue of the feedstock, or alternatively the micro carbon residue content. The Conradson carbon residue / micro carbon residue content of the heavy hydrocarbon feed can be 5.0 wt% to 50 wt%, or 5.0 wt% to 30 wt%, or 10 wt% to 40 wt%, or 20 wt% to 50 wt%.Slurry Hydroprocessing Reaction Conditions

[0061] Slurry hydroprocessing can be performed by processing a feed in one or more slurry hydroprocessing reactors. In some aspects, the slurry hydroprocessing can be performed in a singlereactor, or in a group of parallel single reactors. Alternately, multiple slurry hydroprocessing reactors may be staged in series. The reaction conditions in a slurry hydroprocessing reactor can vary based on the nature of the catalyst, the nature of the feed, the desired products, and / or the desired amount of conversion.

[0062] With regard to catalyst, several options are available. In some aspects, the catalyst can correspond to one or more catalytically active metals in particulate form and / or supported on particles. The catalytically active metal may be molybdenum in some examples, such as phosphomolybdic acid or a product formed from phosphomolydic acid. Illustrative examples of catalysts suitable for performing slurry hydroprocessing include those described in U.S. Patents 5,039,392 and 4,740,489, each of which is incorporated herein by reference. The catalyst may be sulfided. In other aspects, the catalyst can correspond to particles that are retained within the heavy hydrocarbon feed after using a paraffinic froth treatment to form the feed provided to the slurry hydroprocessing reaction. Thus, in some aspects, an additional catalyst may be omitted (not present). In still other aspects, a mixture of catalytically active metals and particles retained in the heavy hydrocarbon feed can be used.

[0063] In aspects where a catalytically active metal is used as the catalyst, suitable catalyst concentrations can range from about 50 wppm to about 50,000 wppm (or roughly 5.0 wt%), depending on the nature of the catalyst. Additionally or alternately, the slurry hydroprocessing may be conducted in the presence of 10 wppm to 500 wppm of catalyst, which may be an additional catalyst comprising a catalytically active metal or a catalytic metal associated with particles retained in the bitumen following a paraffinic froth treatment. Catalyst can be incorporated into a hydrocarbon feed directly, or the catalyst can be incorporated into a side or slip stream of feed and then combined with the main flow of feed being provided to a slurry hydroprocessing reactor. Still another option is to form catalyst in situ by introducing a catalyst precursor into a feed (or a side / slip stream of feed) and forming catalyst by a subsequent reaction, such as in the slurry hydroprocessing reactor.

[0064] Catalytically active metals for use in slurry hydroprocessing can include those from Groups 4 - 10 of the IUPAC Periodic Table. Examples of suitable metals include iron, nickel, molybdenum, vanadium, tungsten, cobalt, ruthenium, and mixtures thereof. The catalytically active metal may be present as a solid particulate in elemental form or as an organic compound or an inorganic compound such as a sulfide (e.g.. molybdenum sulfide) or other ionic compound. Metal or metal compound nanoaggregates may also be used to form the solid particulates. Phosphomolybdic acid may also be used as a source of catalytically active metal.

[0065] A catalyst in the form of a solid particulate is generally a compound of a catalytically active metal, or a metal in elemental form, either alone or supported on a refractory material such as an inorganic metal oxide (e.g., alumina, silica, titania, zirconia, and mixtures thereof). Other suitable refractory materials can include carbon, coal, and clays. Zeolites and non-zeolitic molecular sieves are also useful as solid supports. One advantage of using a support is its ability to act as a "coke getter" or adsorbent of asphaltene precursors that might otherwise lead to fouling of process equipment.

[0066] In some aspects, it can be desirable to form catalyst for slurry hydroprocessing in situ, such as forming catalyst from a metal sulfate catalyst precursor or another type of catalyst precursor that decomposes or reacts in a hydroconversion reaction zone environment, or in a pretreatment step, to form a desired, well-dispersed and catalytically active solid particulate. Precursors also include oil-soluble organometallic compounds containing the catalytically active metal of interest that thermally decompose to form the solid particulate having catalytic activity. Other suitable precursors include metal oxides that may be converted to catalytically active (or more catalytically active) compounds such as metal sulfides. In a particular embodiment, a metal oxide containing mineral may be used as a precursor of a solid particulate comprising the catalytically active metal on an inorganic refractory metal oxide support (e.g., alumina).

[0067] In some aspects, the reactor conducting the slurry hydroprocessing can be configured to use particles present in the input flow to the reactor (i.e., the heavy hydrocarbon feed, such as bitumen) as at least a portion of the catalyst. For example, during slurry hydroprocessing, substantially all of the catalyst used in the reactor can correspond to particles that are included in the input flow to the reactor and / or catalyst particles that are created in situ within the reactor. In such aspects, one option can be to use particles from the extraction source (e.g., an oil sands reservoir) as at least a portion of the catalyst. In such aspects where particles from the extraction source for the heavy hydrocarbon feed are used as at least a portion of the catalyst (or the whole amount of catalyst), suitable catalyst concentrations in the input flow to the reactor conducting the slurry hydroprocessing can range from 1.0 wt% to 10 wt%, or 2.0 wt% to 10 wt%, or 3.0 wt% to 10 wt%.

[0068] Generally, the slurry hydroprocessing can be performed at any convenient level of net conversion relative to 524°C, relative to 538°C, or relative to 566°C. For example, the slurry hydroprocessing stage can be operated under conventional conditions to produce a net conversion of 20 wt% or more relative to 566°C, or 30 wt% or more, such as up to 89 wt%. Additionally or alternately, the slurry hydroprocessing can be operated at a net conversion of 20 wt% or more relative to 524°C, or 30 wt% or more, such as up to 89 wt%. Accordingly, in non-limitingexamples, the net conversion relative to 524 °C, relative to 538°C, or relative to 566°C may range from 90% or less, or 80% or less, or 70% or less, to 40% or more or 50% or more, or 60% or more, such as 40% to 90%, or 50 % to 90%, or 60% to 90%, or 70% to 90%, or 80% to 90%. In at least one non- limiting example, the conversion relative to 524°C may range from 60 wt% to 89 wt%.

[0069] In addition to operating at reduced conversion, the slurry hydroprocessing can also perform a relatively low level of hydrodesulfurization and / or hydrodenitrogenation. In various aspects, the amount of nitrogen removal (conversion to NH3 or other light end nitrogen compounds) can correspond to 35 wt% or less of the organic nitrogen in the feed to the slurry hydroprocessing reactor, or 30 wt% or less, or 25 wt% or less, such as down to 10 wt% or possibly still lower. Additionally or alternately, the amount of sulfur removal (conversion to H2S or other light end sulfur compounds) can correspond to 90 wt% or less of the sulfur in the feed to the slurry hydroprocessing reactor, or 85 wt% or less, or 80 wt% or less, such as down to 30 wt% or possibly still lower. For example, the amount of sulfur removal can correspond to 30 wt% to 90 wt%, or 60 wt% to 90 wt%, or 70 wt% to 85 wt%.

[0070] In some aspects, the slurry hydroprocessing can be operated under conditions involving relatively high recycle rates. In such aspects, slurry hydroprocessing can be operated at a net conversion of 60 wt% to 89 wt%, relative to a temperature of 524°C or alternatively relative to 566°C, or 70 wt% to 89 wt%, or 60 wt% to 85 wt%, or 70 wt% to 85 wt%, or 75 wt% to 89 wt%. Optionally but preferably, the slurry hydroprocessing may be conducted in a single slurry hydroprocessing reactor, as opposed to having a plurality of reactors arranged in series. In such aspects, a portion of the pitch or unconverted bottoms from the slurry hydroprocessing reactor can be recycled. In such aspects, the per-pass conversion can be significantly lower, such as having a per-pass conversion of 89 wt% or less, or 80 wt% or less, or 70 wt% or less, or 60 wt% or less, or 50 wt% or less, or 40 wt% or less, relative to 524°C or alternatively relative to 566°C.

[0071] It is noted that reducing or minimizing the amount of vacuum gas oil that is exposed to hydroconversion while operating with pitch recycle can generate a product with increased vacuum gas oil content and reduced or minimized content of 1050°F+ (566°C+) components. This can provide benefits in later processing. For example, it is believed that reducing or minimizing the 566°C+ content in the effluent from the slurry hydroprocessing reactor can reduce or minimize production of main column bottoms if the effluent is used as a feed for fluid catalytic cracking.

[0072] In aspects where a portion of the slurry hydroprocessing pitch is recycled, the per-pass conversion level for the slurry hydroprocessing reactor can be selected so that the pitch or bottoms fraction provides a sufficient amount of recycle. The amount of recycle can correspond to 10 wt% to 250 wt% or 50 wt% to 250 wt% of the flow of fresh vacuum bottoms into the slurryhydroprocessing reactor. Optionally, the separation of products from the slurry hydroprocessing reactor can be selected so that more than 50 wt% of the recycled pitch corresponds to 566°C+ components, or 60 wt% or more, or 90 wt% or more. Thus, the conversion level during a single pass and the subsequent separation of products can be selected so that a) a sufficient amount of recycled pitch is available, and b) the net conversion corresponds to a target conversion of less than 90 wt% relative to 524°C. In some aspects, it has been discovered that operating with pitch recycle and / or increased pitch recycle can reduce or minimize the amount of diluent required in the heavy hydrocarbon product obtained as an effluent from the slurry hydroprocessing. Without being bound by any particular theory, it is believed that increasing pitch recycle while maintaining a relatively low net conversion, the amount of aromatic compounds present in the slurry hydroconversion effluent can be increased, resulting in improved solvency for the final heavy hydrocarbon product. This can reduce or minimize the amount of additional naphtha (or other diluent) that is needed to allow the processed heavy hydrocarbon product to be suitable for pipeline transport.

[0073] An alternative way of expressing the amount of recycled pitch versus fresh vacuum bottoms can be based on a “recycled pitch ratio”. The recycled pitch ratio can also be referred to as a combined feed ratio. In this discussion, the combined feed ratio is defined, on a mass basis, as the combined amount of fresh vacuum bottoms (or alternatively deasphalter rock) plus recycled pitch, divided by the amount of fresh vacuum bottoms (or alternatively deasphalter rock). Based on this definition, the combined feed ratio has a value of 1.0 when there is no recycle. The value of the ratio increases as more pitch is recycled. When the amount of recycled pitch is equal to the amount of fresh vacuum bottoms the combined feed ratio is 2.0. The advantage of this definition for the combined feed ratio is that it is easy to understand the flow rate into the slurry hydroprocessing reactor. A ratio of 1.0 means that the reactor is sized / operated to receive only fresh feed. A ratio of 2.0 means that the reactor needs to be able to handle a feed volume that is twice the rate of fresh feed. In aspects where pitch is recycled for combination with the fresh vacuum bottoms (or alternatively deasphalter rock), the combined feed ratio to the slurry hydroprocessing conditions can range from 1.1 to 3.5, or 1.1 to 3.0, or 1.5 to 3.5, or 1.5 to 3.0, or 1.1 to 2.5, or 1.5 to 2.5.

[0074] The reaction conditions (slurry hydroprocessing conditions) within a slurry hydroprocessing reactor that correspond to a selected conversion amount can include a temperature of 360°C to 480°C, or 360°C to 420°C, or 400°C to 480°C, or 425°C to 480°C, or 450°C to 480°C. Some types of slurry hydroprocessing reactors are operated under high hydrogen partial pressure conditions, such as having a hydrogen partial pressure of 1000 psig (6.9 MPag) to 3400 psig (23.4MPag), for example at least 1200 psig (8.3 MPag), or at least about 1500 psig (10.3 MPag). Examples of hydrogen partial pressures can be 1000 psig (6.9 MPag) to 3000 psig (20.7 MPag), or 1000 psig (8.3 MPag) to 2500 psig (17.2 MPag), or 1500 psig (10.3 MPag) to 3400 psig (23.4 MPag), or 1000 psig (6.9 MPag) to 2000 psig (13.8 MPag), or 1200 psig (8.3 MPag) to 2500 psig (17.2 MPag). Since the catalyst is present in slurry form within the feedstock, the space velocity for a slurry hydroconversion reactor can be characterized based on the volume of feed processed relative to the volume of the reactor used for processing the feed. Suitable space velocities for slurry hydroconversion can range, for example, from about 0.05 v / v / hr1to about 5 v / v / hr1, such as about 0.1 v / v / hr1to about 2 v / v / hr1.

[0075] In some aspects, the quality of the hydrogen stream used for slurry hydroprocessing can be relatively low. For example, in aspects where the catalyst is concentrated into the pitch and removed from the system without being recycled, catalyst lifetime can be of minimal concern. This is due to the constant addition of fresh catalyst, whether in the form of particles from the heavy hydrocarbon feed or in the form of a separately added catalyst. As a result, reaction conditions that conventionally are considered undesirable for slurry hydroprocessing due to catalyst deactivation can potentially be used in the disclosure herein. This can potentially provide unexpected synergies when a partial oxidation reactor is used to provide at least a portion of the hydrogen for the hydroconversion process, as discussed further below.

[0076] One example of a reaction condition that is avoided in slurry conventional hydroprocessing is use of hydrogen streams that have relatively high concentrations of known catalyst poisons. Some catalyst poisons can correspond to catalyst poisons commonly found in recycled hydrogen treat gas streams, such as H2S, NH3, CO, and other contaminants. Other catalyst poisons can correspond to contaminants that may be present in hydrogen derived from processing of pitch in a partial oxidation reactor, such as nitrogen oxides (NOx), sulfur oxides (SOx), arsenic compounds, and / or boron compounds. In order to use hydrogen generated by partial oxidation of pitch obtained from a conventional hydroprocessing reactor, various cleanup processes may be utilized to reduce or minimize the content of various contaminants in the hydrogen gas provided to the slurry processing reactor. However, using a partial oxidation reactor to provide hydrogen for a slurry hydroprocessing reactor can provide the unexpected synergy of allowing at least some cleanup steps to be avoided, due to the tolerance of the slurry hydroprocessing reaction conditions for the presence of various contaminants.

[0077] In some aspects, the H2 content of a hydrogen-containing stream introduced into the slurry hydroprocessing reactor can be 90 vol% or less, or 80 vol% or less, or 60 vol% or less, such as down to 40 vol% or possibly still lower. In other aspects, the H2 content of the hydrogen-containing stream can be 80 vol% or more, or 90 vol% or more. For example, the hydrogencontaining stream can contain 80 vol% to 100 vol% H2, or 90 vol% to 100 vol%, or 80 vol% to 98 vol%, or 90 vol% to 98 vol%, or 80 vol% to 96 vol%, or 90 vol% to 96 vol%. Additionally or alternately, the combined content of H2S, CO, and NH3 in the hydrogen-containing stream can be 1.0 vol% or more, or 3.0 vol% or more, or 5.0 vol% or more, such as up to 15 vol% or possibly still higher. Further additionally or alternately, the combined content of H2, H2O, and N2 in the hydrogen-containing stream introduced into the slurry hydroprocessing reactor can be 95 vol% or less, or 90 vol% or less, or 85 vol% or less, such as down to 75 vol% or possibly still lower. For example, the combined content of H2, H2O, and N2 in the hydrogen-containing stream introduced into the slurry hydroprocessing reactor can be 75 vol% to 95 vol%.

[0078] Before discussing more particular aspects and advantages of the present disclosure in further detail, the processes of the present disclosure will be described with reference to the drawings.

[0079] FIG. 1 is a block diagram of an illustrative slurry hydroprocessing reactor system 400. In FIG. 1, feed 405 is mixed with at least one of fresh slurry hydrotreating catalyst 402 and hydrogen stream 401 prior to being introduced into slurry hydroprocessing reactor 410. Optionally, a catalyst precursor (not shown) can be added to feed 405 in place of at least a portion of slurry hydrotreating catalyst 402. Optionally, hydrogen stream 401 and / or slurry hydrotreating catalyst 402 can be introduced into slurry hydroprocessing reactor 410 separately from feed 405. In the configuration shown in FIG. 1 , pitch recycle stream 465 (discussed subsequently) is combined with feed 405 upstream from slurry hydroprocessing reactor 410. In other aspects, pitch recycle stream 465 and feed 405 can be introduced separately into slurry hydroprocessing reactor 410.

[0080] After exposing the feed to slurry hydroprocessing conditions in slurry hydroprocessing reactor 410, the resulting slurry hydroprocessing effluent 415 can be passed into one or more separation stages. In the configuration shown in FIG. 1, the separation stages include first separator 420 and second separator 430. First separator 420 may perform a high-pressure vapor-liquid separation. Vapor fraction 422 corresponds to light gases and at least part of the reaction products. Liquid fraction 425 corresponds to a combination of vacuum gas oil and pitch. Liquid fraction 425 is passed into second separator 430, where pitch fraction 465 is separated from second product fraction 432. Second separator 430 can correspond to any convenient type of separator suitable for processing a pitch fraction, such as a vacuum distillation tower or a flash separator. As shown, a portion of pitch fraction 463 may be recycled to slurry hydroprocessing reactor 410. The portion of pitch fraction 465 being recycled can be passed into pitch recycle pump 463 prior to beingcombined with feed 405 and / or separately introduced into slurry hydroprocessing reactor 410. A second portion of pitch fraction 465 (or all of pitch fraction 465) may be directed to pitch removal stream 437.

[0081] Both vapor fraction 422 and second product fraction 432 can optionally undergo further separations and / or additional processing, as desired. For example, as shown in FIG. 1, vapor fraction 422 can be passed into a subsequent hydrotreating or stabilizer stage 450 to form hydrotreated vapor fraction 452. In some aspects, the light gases in vapor fraction 422 can include sufficient hydrogen for performing the subsequent hydrotreating in stabilizer stage 450. In nonlimiting examples, the subsequent hydrotreating can be used to reduce olefin content, reduce heteroatom content (such as nitrogen and / or sulfur), or a combination thereof. In the example shown in FIG. 1, a hydrotreated or stabilized effluent 452 is obtained from stabilizer stage 450 after hydroconversion of naphtha and distillate boiling range portions of vapor fraction 422. In such aspects, second product fraction 432, including at least a portion of the vacuum gas oil, can bypass the hydrotreating in stabilizer stage 450. In other aspects, both the vapor fraction 422 and second product fraction 432 can be passed into the hydrotreating in stabilizer stage 450 (configuration not shown in FIG. 1). Optionally, the hydrotreating may be integrated with the hydroconversion occurring in slurry hydroprocessing reactor 410. For example, an initial separator can be used to separate the hydroconverted effluent into a lighter portion and a heavier portion that includes the bottoms. Such a separation can be performed at substantially the exit pressure following hydroconversion. Additionally, any hydrogen in the gas exiting with the effluent can travel with the lighter portion. In some aspects, the hydrogen exiting with the lighter portion of the effluent can be sufficient to provide substantially all of the hydrogen treat gas that is needed for performing hydrotreating in stabilizer stage 450. Vapor fraction 422 (plus hydrogen) can then be passed into stabilizer stage 450 without requiring re -pressurization. In other aspects, additional hydrogen can be provided to the hydrotreating in stabilizer stage 450, such as hydrogen generated from partial oxidation of pitch and / or hydrogen from another convenient source.

[0082] In the configuration shown in FIG. 1, a recirculation loop is also shown. In the recirculation loop, portion 446 of liquid fraction 425 is passed through recycle pump 443 prior to passing portion 446 into slurry hydroprocessing reactor 410.

[0083] FIG. 2A is a block diagram of a first configuration for integrating a paraffinic froth treatment process with a slurry hydroprocessing process according to the present disclosure. In FIG. 2 A, froth feed 205 is generated from oil sands and exposed to paraffinic froth treatment 210. Paraffinic froth treatment 210 is modified to maintain a desired level of particles and asphaltenes in accordance with the description above. Bitumen 215 is obtained from paraffinic froth treatment210 with an increased particle content relative to conventional paraffinic froth treatments for processing oil sands. In the configuration shown in FIG. 2A, bitumen 215 is passed into optional separation stage 220. In other aspects, the full range bitumen 215 can be passed directly into slurry hydroprocessing stage 230 (see FIG. 2B).

[0084] Optional separation stage 220 can generate bottoms stream 227 that is passed into slurry hydroprocessing stage 230. The bottoms stream can correspond to an atmospheric bottoms, a vacuum bottoms, another convenient higher boiling fraction, or a deasphalter residue or rock. The optional separation stage 220 can also generate a lighter stream 225. Lighter stream 225 can correspond to one or more of naphtha, distillate, atmospheric gas oil, and deasphalted oil.

[0085] The full range bitumen 215 or the optionally formed bottoms stream 227 can then be processed in slurry hydroprocessing stage 230. The slurry hydroprocessing stage can generate a gas phase product 232, a liquid effluent 235, and a pitch or residue product 237. The pitch can be further processed in a convenient manner. For example, the pitch can be passed into a partial oxidation reactor (not shown) for conversion of the pitch. A partial oxidation reactor can also be beneficial for processing the pitch, as the partial oxidation reaction provides a method for converting the hydrocarbons in the pitch in the presence of any particles concentrated in the pitch fraction. Hydrogen may be formed in the partial oxidation reaction. The gas phase product 232 can correspond to light hydrocarbons (C4-) and contaminant gases generated during the hydroprocessing (such as H2S or NH3). The liquid effluent 235 corresponds to the desired product. If the full range bitumen 215 is passed into slurry hydroprocessing stage 230, then the liquid effluent can correspond to the upgraded bitumen product. In other aspects, such as the configuration shown in FIG. 2A, a lighter portion 225 of the bitumen is separated out prior to exposing the bottoms 227 to the slurry hydroprocessing. In such aspects, the lighter portion 225 can be combined with liquid effluent 235 to form an upgraded bitumen product 245.

[0086] FIG. 2B is a block diagram of a second configuration for integrating a paraffinic froth treatment process with a slurry hydroprocessing process according to the present disclosure. The second configuration for integrating a paraffinic froth treatment process with a slurry hydroprocessing process shown in FIG. 2B differs from the first configuration shown in FIG. 2A in that separation stage 220 is omitted and bitumen 215 is passed directly to slurry hydroprocessing stage 230. Gas phase product 232, pitch 237, and upgraded bitumen product 245 are obtained from slurry hydroprocessing reactor 230. Optionally, pitch 237 may be processed as described above. Further optionally, upgraded bitumen product 245 may be further processed as well.Partial Oxidation Reactor

[0087] In various aspects, the portion of the pitch that is not recycled back to the slurry hydroprocessing reactor (or other hydroconversion reactor) can be passed into a partial oxidation reactor. A partial oxidation reactor can be used to convert the slurry hydroprocessing pitch into hydrogen, carbon monoxide, and ash which can then be pelletized. The hydrogen generated during partial oxidation can be used as at least part of the hydrogen delivered to the slurry hydroprocessing reactor and / or the stabilizing hydrotreater. The pelletized ash thus corresponds to the other carbon- containing product that requires transport away from the extraction site.

[0088] In some aspects, the portion of the pitch used as the input flow to a partial oxidation reactor can, following partial oxidation, have an ash content of 1.0 wt% or more, or 2.0 wt% or more, or 10 wt% or more, or 20 wt% or more, such as up to 40 wt%.Staged Paraffinic Froth Treatment

[0089] In various alternative aspects, instead of increasing the amount of particles retained in a bitumen formed during paraffinic froth treatment, the paraffinic froth treatment can be performed in a staged manner. By using multiple stages for the paraffinic froth treatment, a desired level of particle removal can be achieved while also increasing the amount of hydrocarbons recovered as part of the bitumen in the form of asphaltenes. By using staged paraffinic froth treatment, losses of asphaltenes can be reduced to levels comparable to a naphthenic froth treatment while still removing particles and water to levels more typically associated with a paraffinic froth treatment. That is, a staged paraffinic froth treatment may realize the benefits of both conventional naphthenic and paraffinic froth treatments. The number of stages is not considered to be particularly limited. In particular examples, the number of stages may be two, three, four, five, six, or even more.

[0090] In such alternative aspects, systems and methods are provided for performing paraffinic froth treatment with increased bitumen recovery at parity and / or similar to the bitumen recovery from a conventional naphthenic froth treatment. This constitutes a significant increase in total bitumen recovery over conventional paraffinic froth treatment processes. The high bitumen recovery is achieved while still creating a bitumen having a low water content and a low solids content. Conventional paraffinic froth treatment processes may reject 10-12% of incoming bitumen, primarily asphaltenes, to tailings in order to create a low solids and water bitumen product. Such conventional approaches may utilize a 2-stage counter-current gravity driven settler operation where the first stage includes simultaneous emulsion breaking and asphaltene precipitation which induces an overhead bitumen product cleaning. The underflow from that stage may then be washed with solvent to enhance maltene recovery which is recycled to the feed and first stage.

[0091] By contrast, in various alternative aspects, a staged approach is used to achieve both a relatively clean bitumen product and with a high bitumen recovery. The core elements may include an initial paraffinic solvent addition step and liquid- liquid separation followed by a second solvent addition step and liquid-liquid separation. The first step uses a typical froth feed and paraffinic solvent to break the water-bitumen emulsion creating a bitumen- and solvent-rich phase and an aqueous phase. This first solvent addition is performed such that substantially no asphaltenes precipitate from the bitumen- and solvent-rich phase. The phases are then separated which causes partitioning of the solids between the bitumen- and solvent-rich phase and the aqueous phase based on the settling characteristics of the solids. Finer solids remain in the bitumen- and solvent-rich phase while larger solids separate with the aqueous phase.

[0092] The bitumen- and solvent-rich phase undergoes further solvent addition which induces partial precipitation of asphaltenes from the bitumen- and solvent-rich phase. Water may also be added prior to the further solvent addition. The partial precipitation removes remaining fine solids as well as water, such that after separation from the second aqueous phase, a relatively clean bitumen product is created. Optionally, the underflow from one or both stages can be washed with solvent to enhance maltene recovery which can be accomplished in a single vessel, and the resulting solvent-rich stream can be recycled to solvent addition points upstream of the first and second stages, respectively. The resulting aqueous and solids stream from this step may contain minimal remaining hydrocarbon but may need solvent recovery treatment before being sent to tailings. As such, the foregoing operations may achieve relatively high recovery of both asphaltenes and maltenes from an oil sands source.During a staged paraffinic froth treatment, the first stage can have a solvent to bitumen ratio of 1.0 or less, such as a solvent to bitumen ratio of 0.8 to 1.0. The solvent to bitumen ratio in the second stage can be increased to between 1.1 to 1.3. The mixing and settling temperature during a staged paraffinic froth treatment can be between 60°C and 100°C, or 70°C to 100°C, or 70°C to 90°C. After the first paraffinic froth treatment stage, the overflow product passed to the second paraffinic froth treatment stage can have a particle content of 1.0 wt% to 7.0 wt%. The particle content of the overflow product can include up to 0.5 wt% of particles having a particle size of 45 pm or more.

[0094] Another benefit of conducting a staged paraffinic froth treatment is a reduction in total energy costs. By reducing or minimizing the amount of solvent that is added to bitumen during the paraffinic froth treatment, the amount of solvent that has to be distilled off from the product is also reduced. For example, by reducing the solvent to bitumen ratio in the separation stage from1.4 to 1.1, a roughly 30% reduction in fuel use during distillation for solvent recovery can be realized.

[0095] FIG. 3 is a block diagram of a system 600 for performing a staged paraffinic froth treatment, which may be performed with a reduced solvent to bitumen ratio in accordance with the description above. In FIG. 3, bitumen feed 601, which may be obtained from oil sands, is mixed with solvent 604 in a solvent to bitumen volume ratio of 1.0 or less, such as a solvent to bitumen ratio of 0.8 to 1.0. An example of a suitable feed 601 can include 60 wt% bitumen, 25 wt% to 30 wt% water, and 10 wt% to 15 wt% solids. Solvent 604 can optionally correspond to a stream of recycled solvent. The resulting first mixture of solvent and bitumen is passed into first settling stage 610. For the first mixture, the solvent to bitumen ratio is selected to be sufficient to break the emulsion so that a separate water phase is formed. Because of the low ratio of solvent to bitumen, coarse solids are transferred to the water phase, and at least a portion of the fine solids (e.g. less than 45 pm in size) are retained in the hydrocarbon and solvent phase. Even though coarse particles are being transferred to the water phase, the solvent to bitumen ratio is low enough to reduce or minimize the associated transfer of asphaltenes from the hydrocarbon phase to the water phase.

[0096] First settling stage 610 produces overflow stream 615 and underflow stream 617. Underflow stream 617 may include a majority of the water and coarse solids that were present in bitumen feed 601. A portion of the asphaltenes and / or maltenes can also be included in underflow stream 617. Underflow stream 617 can be sent to tailings unit 619 for further separation of solids from the water, as well as for recovery of solvent. Overflow stream 615 includes bitumen, solvent, and fine solids. Overflow stream 615 may be substantially free of water, or some residual water may be present. Water 621 and / or additional solvent 624 can optionally be added to overflow stream 615 to form second mixture 625 comprising solvent and bitumen. The amount added may be selected for sufficiency for transport to a subsequent settling stage. Second mixture 625 can be passed into second settling stage 630. Sufficient water 621 can be added to allow two phases to form in second settling stage 630. An emulsion need not necessarily be formed in second settling stage 630; a biphasic mixture is sufficient. The amount of additional solvent 624 can be sufficient to increase the solvent to bitumen volume ratio to 1.1 to 1.3.

[0097] The increased solvent to bitumen ratio in second settling stage 630 can allow a substantial portion of the fine particles to transfer into the water phase. Since coarse particles were removed in the first settling stage, the overall particles being transferred to the water phase are fewer in number and smaller in volume. This reduces or minimizes the quantity of asphaltenes that agglomerate on the particles and also transfer into the water phase. Thus, by performing theparticle removal in stages so that coarse solids and fine solids are removed in separate stages, a high efficiency of particle removal can be achieved while reducing or minimizing the presence of conditions that cause co-transfer of asphaltenes with the particles.

[0098] Second settling stage 630 generates overflow stream 635 and underflow stream 637. Overflow stream 635 is sent to a solvent recovery unit (such as a distillation column, not shown) for separation of solvent from the hydrocarbon product (bitumen). The solids content of overflow stream 635 can be similar to a conventional paraffinic froth treatment (0.03 wt% or less), while the bitumen content of overflow stream 635 can correspond to 90 wt% or more, or 92 wt% or more, 94 wt% or more, or 96 wt% or more, or 97.5 wt% or more, or 98.5 wt% or more of the bitumen from the feed, including up to 99.5 wt% or possibly still higher. The corresponding amounts of retained asphaltenes from the feed may be 70 wt% or more, or 75 wt% or more, or 80 wt% or more, or 85 wt% or more, or 90 wt% or more. More generally, the solids content of overflow stream 635 may be about 0.5 wt% or less, or about 0.4 wt% or less, or about 0.3 wt% or less, or about 0.2 wt% or less, or about 0.1 wt% or less, or about 0.05 wt% or less, or about 0.01 wt% or less. Optionally, underflow stream 637 may include a majority of the water and fine solids that were present in second mixture 625, along with some asphaltenes and solvent. Further optionally, underflow stream 637 can he mixed with second additional solvent 644 and passed into third settling stage 660. Due to the limited content of hydrocarbons in underflow stream 637, only a modest amount of second additional solvent 644 may be needed to achieve a high solvent to bitumen volume ratio, such as a volume ratio of 2.0 or more. This higher solvent to bitumen ratio can allow for extraction of any remaining maltenes that are entrained with the water and fine solids from underflow stream 637. Third settling stage 660, if present, can produce a tailings stream 667 that is sent to a tailings and solvent recovery unit. The third settling stage 660, if present, can also produce hydrocarbon phase 665 that can be used as a recycle solvent. For example, hydrocarbon phase 665 can be used as solvent 604, as additional solvent 624, or as both solvent 604 and additional solvent 624. This can allow any maltenes extracted in third settling stage 660 to be combined with the hydrocarbon product in overflow stream 635. In some aspects, second additional solvent 644 can correspond to fresh solvent. Doing so creates a counter-current solvent flow, so that the highest purity solvent (additional solvent 644 is fresh solvent) is used to treat the stream with the lowest concentration of hydrocarbons (underflow stream 637).

[0099] In some alternative aspects, instead of having a counter-current flow of solvent, solvent stream 604 and additional solvent 624 can correspond to fresh solvent. In such aspects, the third settling stage 660 can be removed. Instead, underflow stream 637 can be passed to a tailings and solvent recovery unit, similar to underflow stream 617. This type of alternate configurationreduces the amount of equipment footprint, but also reduces the amount of additional maltenes that are recovered so that the net yield of hydrocarbon is slightly reduced.

[0100] A staged paraffinic froth treatment can provide additional synergistic benefits when used in conjunction with slurry hydroprocessing. FIG. 4 is a block diagram of an integrated system and process having a staged paraffinic froth treatment portion and a slurry hydroprocessing portion. In FIG. 4, system and process 700 includes staged paraffinic froth treatment portion 700a and slurry hydroprocessing portion 700b. Staged paraffinic froth portion 700a, described in more detail hereinafter, is similar to system 600 (FIG. 3) and may be better understood by further reference thereto. Slurry hydroprocessing portion 700b similarly includes aspects of FIGS. 2A and 2B and may be better understood by further reference thereto. Referring to FIG. 4, initial froth feed 701 is mixed with recycled solvent 704 to form a mixture with a solvent to bitumen volume ratio of less than 1.0. The mixture is passed into first separation stage 710 to produce overflow stream 715 and underflow stream 717 that includes coarse solids. Overflow stream 715 is mixed with water 721 and additional recycled solvent 724 to form a second mixture that is passed into second separation stage 730. Second separation stage 730 produces underflow stream 737 and overflow stream 735 containing 96 wt% or more of the bitumen from initial froth feed 701. Underflow stream 737 is passed into third separation stage 760 to produce fines tailings stream 767 and the recycled solvent streams 704 and 724.

[0101] Overflow stream 735 proceeds to separation vessel 780 (e.g., a distillation tower), and frothing solvent 784 is separated from bitumen 745. Bitumen 745 is then passed into slurry hydroprocessing portion 700b.

[0102] In alternative aspects, bitumen 745 can be transported via pipeline to a remote slurry hydroprocessing system. In such aspects, an optional diluent recycle loop 739 can be used. Diluent recycle loop 739 can deliver sufficient diluent to bitumen 745 to meet any required pipeline specifications. The diluent can then be separated from bitumen 745 after transport, and the recycle loop can return the diluent to the paraffinic froth treatment portion 700a for further use. In still other alternative aspects, the paraffinic froth treatment portion 700a and the slurry hydroprocessing portion 700b can communicate via a conventional conduit, without needing separate pipeline transport for bitumen 745.

[0103] Referring again to FIG. 4, bitumen 745 is then passed into one or more separation stages to separate bottoms fraction 755. In the example shown in FIG. 4, atmospheric separator 751, vacuum separator 752, and deasphalting unit 753 are linked in series, with bottoms fraction 755 being obtained from deasphalting unit 753. The overhead fractions from atmospheric separator 751, vacuum separator 752, and deasphalting unit 753 can, for example, be passed into finalproduct 799. The overhead fractions may travel to final product 799 in a single line, or one or more of the overhead fractions may travel to final product 799 in a separate line. Formation of final product 799 is discussed subsequently.

[0104] Bottoms fraction 755 is passed into slurry hydroprocessing unit 770 to promote upgrading thereof. Optionally, fines tailings stream 767 can also be passed into slurry hydroprocessing unit 770, so that the fine particles from the bitumen feed can serve as additional catalyst during the slurry hydroprocessing. As shown, fines tailings stream 767 is introduced into bottoms fraction 755 upstream from slurry hydroprocessing unit 760, but may alternately be introduced directly to slurry hydroprocessing unit separately from bottoms fraction 755. Alternately, the fines tailings stream 767 can be handled in a conventional manner. For example, fines tailings stream 767 may be sent to a tailings unit (not shown) for further separation of particles.

[0105] Slury hydroprocessing unit 770 produces light ends 771, conversion effluent 775 and bottoms fraction 779, which may comprise pitch or unconverted material. Conversion effluent, after optional additional hydroprocessing 790, can be added to form a portion of final product 799, with the overhead fractions defining the remainder of final product 799. Bottoms fraction 779 can be disposed of in a conventional manner. Alternatively, and as shown in FIG. 4, bottoms fraction 779 can be recycled to paraffinic froth treatment portion 700a for combination with initial froth feed 701 in order to further process the bottoms fraction 779 in the various separation stages therein. By recycling bottoms fraction 779, still further improvements in net hydrocarbon yield may be realized.

[0106] One of the benefits of using a staged paraffinic froth treatment, such as those shown in FIGS. 3 and 4, is that an increased settling rate can be achieved at lower solvent to bitumen ratios. Without being bound by any particular theory, it is believed that by removing coarse particles in a first paraffinic froth treatment stage, the fine particles can agglomerate more efficiently into larger particles in subsequent treatment stages, thus reducing or minimizing the number of fine particles that need to settle as individual particles. This action may result in a net increase in the settling rate for the remaining fine particles in the subsequent treatment stages.

[0107] In a continuous process, the throughput for the process is determined by the stage with the longest residence time. For a multi-stage paraffinic froth treatment process, the second (or other final) stage can correspond to the slowest settling rate and / or longest residence time stage. Thus, a comparison between a single-stage and a multi-stage paraffinic froth treatment process can be made based on comparing a single-stage paraffinic froth treatment process with the second (final) stage of a staged paraffinic froth treatment process.Embodiments

[0108] Embodiment 1. A method for upgrading oil sands, comprising: exposing oil sands to a water extraction process to form a froth, the oil sands comprising particles and asphaltenes; adding a paraffinic froth solvent to the froth under froth treatment conditions to form a bitumen comprising 0.05 wt% or more particles, based upon total mass of the bitumen; wherein about 80 wt% or more of the asphaltenes from the oil sands are retained in the bitumen; and exposing at least a portion of the bitumen obtained from the froth treatment conditions to slurry hydroprocessing conditions in a slurry hydroprocessing reactor in the presence of the particles to form a light ends fraction, a slurry hydroprocessing effluent, and a pitch fraction, the slurry hydroprocessing conditions affording 90% conversion or less of the bitumen to 566°C.

[0109] Embodiment 2. The method of Embodiment 1 , wherein exposing at least a portion of the bitumen to slurry hydroprocessing conditions comprises: performing a boiling point separation on at least a portion of the bitumen to form a lower boiling fraction and a higher boiling fraction; and exposing at least a portion of the higher boiling fraction to the slurry hydroprocessing conditions.

[0110] Embodiment 3. The method of Embodiment 2, wherein performing a boiling point separation comprises: separating the at least a portion of the bitumen under atmospheric separation conditions to form at least an atmospheric bottoms fraction, a fraction comprising the paraffinic froth solvent, and one or more additional fractions comprising 343 °C- compounds, the bitumen having an API gravity of 15° or less; and separating at least a portion of the atmospheric bottoms fraction under vacuum separation conditions to form at least a vacuum bottoms fraction and one or more vacuum gas oil fractions, the vacuum bottoms fraction comprising the particles.

[0111] Embodiment 4. The method of any one of Embodiments 1-3, wherein exposing at least a portion of the bitumen to slurry hydroprocessing conditions comprises: performing solvent deasphalting on at least a portion of the bitumen to form deasphalted oil and deasphalter rock; and exposing at least a portion of the deasphalter rock to the slurry hydroprocessing conditions.

[0112] Embodiment 5. The method of Embodiment 4,_wherein solvent deasphalting is performed on a bottoms fraction obtained from a boiling point separation.

[0113] Embodiment 6. The method of any one of Embodiments 1-5, wherein the froth treatment conditions comprise adding the paraffinic froth solvent at a temperature of 85 °C or more, adding the paraffinic froth solvent at a weight ratio of paraffinic froth solvent to bitumen of 1.3 or less, or a combination thereof.

[0114] Embodiment 7. The method of any one of Embodiments 1-6, wherein the bitumen has an API gravity of 15° or less.

[0115] Embodiment 8. The method of any one of Embodiments 1-7, wherein the extraction process comprises a hot water extraction process, the hot water having a temperature of about 80°C to about 85°C.

[0116] Embodiment 9. The method of any one of Embodiments 1-8, wherein the at least a portion of the bitumen is exposed to the slurry hydroprocessing conditions in the presence of 10 wppm to 500 wppm of an additional catalyst comprising a catalytically active metal.

[0117] Embodiment 10. The method of Embodiment 9, wherein the catalytically active metal comprises molybdenum.

[0118] Embodiment 11. The method of any one of Embodiments 1-8, wherein an additional catalyst is not present when the at least a portion of the bitumen is exposed to the slurry hydroprocessing conditions.

[0119] Embodiment 12. The method of any one of Embodiments 1-11, wherein the paraffinic froth solvent comprises Cs to Cs alkanes.

[0120] Embodiment 13. The method of any one of Embodiments 1-12, wherein the bitumen is separated from the paraffinic froth solvent to form a fraction comprising 50 vol% or more of the froth solvent.

[0121] Embodiment 14. The method of Embodiment 13, further comprising: recycling at least a portion of the fraction comprising 50 vol% or more of the paraffinic froth solvent to provide at least a portion of the paraffinic froth solvent added to the froth.

[0122] Embodiment 15. The method of any one of Embodiments 1-14, wherein the slurry hydroprocessing conditions produce a single-pass conversion of 50 wt% or less relative to 566°C.

[0123] Embodiment 16. The method of any one of Embodiments 1-15, further comprising: exposing at least a portion of the pitch fraction to partial oxidation conditions.

[0124] Embodiment 17. The method of any one of Embodiments 1-16, wherein the bitumen comprises about 15 wt% to about 18 wt% asphaltenes.

[0125] Embodiment 18. The method of any one of Embodiments 1-17, wherein the bitumen comprises 0.05 wt% to 10 wt% particles, based on a total mass of the bitumen.

[0126] Embodiment 19. The method of any one of Embodiments 1-17, wherein the bitumen comprises 0.05 wt% to 0.5 wt% particles, based on a total mass of the bitumen.Alternate Embodiments

[0127] Alternate Embodiment 1. A method for upgrading oil sands to form a processed heavy hydrocarbon product, comprising: exposing oil sands to a water extraction process to form a froth comprising oil sands particles, water, and bitumen; mixing a paraffinic froth solvent with the froth under froth treatment conditions to form a mixture comprising a solvent to bitumen volume ratio of 0.8 to 1.0; separating the mixture to form an overflow product comprising 1 .0 wt% to 7.0 wt of the oil sands particles and an underflow product, the overflow product comprising 1.0 wt% to 7.0 wt% of the oil sands particles and 1.0 wt% or less of water, the oil sands particles comprising 0.5 wt% or less of oil sands particles having a size of 45 pm or more relative to a weight of the overflow product; mixing a second paraffinic froth solvent and water with at least a portion of the overflow product under second froth treatment conditions to form a second mixture comprising a solvent to bitumen volume ratio of 1.1 to 1.3; and separating the second mixture to form a second overflow product comprising 0.03 wt% or less of oil sands particles, the second overflow product comprising 96 wt% or more of the bitumen from the froth.

[0128] Alternate Embodiment 2. The method of Embodiment 1 , further comprising separating the second overflow product to form a slurry hydroprocessing feed; and exposing the slurry hydroprocessing feed to slurry hydroprocessing conditions.

[0129] Alternate Embodiment 3. The method of Embodiment 2, wherein separating the second overflow product comprises: separating the second overflow product under atmospheric separation conditions to form at least an atmospheric bottoms fraction, a fraction comprising the froth solvent, and one or more additional fractions comprising 343 °C- compounds; separating at least a portion of the atmospheric bottoms fraction under vacuum separation conditions to form at least a vacuum bottoms fraction and one or more vacuum gas oil fractions, the slurry hydroprocessing feed comprising at least a portion of the vacuum bottoms fraction.

[0130] Alternate Embodiment 4. The method of Embodiment 2 or 3, wherein exposing the slurry hydroprocessing feed to slurry hydroprocessing conditions comprises forming a slurry hydroprocessing effluent and an unconverted pitch fraction, and wherein the unconverted pitch fraction is mixed with the froth and the paraffinic froth solvent to form the mixture.

[0131] Alternate Embodiment 5. The method of any of the above embodiments, wherein the slurry hydroprocessing conditions further comprise exposing at least a portion of the vacuum bottoms fraction to slurry hydroprocessing conditions in the presence of 10 wppm to 500 wppm of an additional catalyst comprising a catalytically active metal.

[0132] Alternate Embodiment 6. The method of any of the above embodiments, wherein the bitumen comprises 15 wt% or more of asphaltenes, relative to a weight of the bitumen.

[0133] Alternate Embodiment 7. The method of Embodiment 6, wherein the underflow product comprises 2.0 wt% or less of asphaltenes, relative to a weight of the bitumen.

[0134] Alternate Embodiment 8. The method of Embodiment 6 or 7, wherein separating the second mixture further comprises forming a second underflow product, the second underflow product comprising 2.0 wt% or less of asphaltenes, relative to a weight of the bitumen.

[0135] Alternate Embodiment 9. The method of Embodiment 8, further comprising separating the second underflow product to form a recovered solvent fraction and an underflow bottoms fraction, the method further comprising mixing at least a portion of the underflow bottoms fraction with the slurry hydroprocessing feed.

[0136] Alternate Embodiment 10. The method of any of the above embodiments, wherein the froth treatment conditions comprise adding the froth solvent at a temperature of 85 °C or more.

[0137] Alternate Embodiment 11. The method of any of the above embodiments, wherein the bitumen comprises an API gravity of 15° or less.

[0138] Alternate Embodiment 12. The method of any of the above embodiments, wherein the extraction process comprises a hot water extraction process.

[0139] Alternate Embodiment 13. The method of any of the above embodiments, wherein the paraffinic froth solvent comprises Cs to Cs alkanes, or wherein the second paraffinic froth solvent comprises Cs to Cs alkanes.

[0140] To facilitate a better understanding of the disclosure herein, the following examples of various representative embodiments are given. In no way should the following examples be read to limit, or to define, the scope of the present disclosure.

[0141] A bitumen feed was upgraded by slurry hydroprocessing under the conditions specified in Table 1. A conventional sulfided Mo catalyst was used for comparative slurry processing reactions (C1-C6), and coke ash was used as a catalyst replacement for an experimental slurry hydroprocessing reaction (El). The sulfided catalyst was prepared from phosphomolybdic acid, as described in U.S. Patent 5,039,392, which is incorporated herein by reference. The coke ash contains particles similar to oil sands particles that are present in oil sands prior to a paraffinic froth treatment._Selected data for the product is also shown for each run. In Table 1, ERT is the equivalent residence time, wherein equivalent residence time is the actual residence time in the reactor scaled to 875°F (468.3°C) conditions.Table 1

[0142] As shown, the API gravity of the slurry hydroprocessing effluent ranged between 15.7 and 23.6 under the varying reaction conditions. The type of reactor had minimal influence on the API gravity result of the product.

[0143] Substituting 6.8 wt% of coke ash for 445 wppm Mo catalyst (comparing runs C7 and El), afforded a comparable API gravity, even with no additional Mo catalyst being added. This result demonstrates the ability to use coke ash as a slurry catalyst under slurry hydroprocessing conditions. It is believed that the results obtained with 6.8 wt% of coke ash particles are comparable and / or representative of the conversion that can be achieved with 2.0 wt% to 5.0 wt% of oil sands particles.

[0144] FIGS. 5-7 show additional results associated with slurry hydroprocessing of various bitumen feeds in the presence of a Mo catalyst and / or in the presence of oil sands particles. FIG. 5 is a graph of toluene-insoluble coke formation obtained during slurry hydroprocessing as function of catalyst or oil sands particle loading. The bitumen-only (no oil sands particles) sample was Cold Lake bitumen, which is produced by a cyclic steam stimulation process and is inherently soilds free. The bitumen plus clay particles sample was Athbasca bitumen (975°F+ (524°C+) bitumenfraction, which is a mined bitumen that is processed by a naphthenic froth treatment to leave behind residual clay particles (1.3 wt.% in this case). Each feed was reacted under slurry hydroprocessing conditions including in the presence of a conventional phosphomolybdic acid-based catalyst under slurry hydroprocessing conditions including exposing the feed to 2100 psig of H in a batch reactor for 3 hours at a temperature of 830°F (-445 °C). This resulted in roughly 88 wt% conversion of the feed.

[0145] As shown in FIG. 5, increasing the amount of Mo catalyst in the slurry hydroprocessing reactor provided an initial reduction in the amount of coke formed under the slurry hydroprocessing conditions, but a plateau was reached where additional Mo catalyst provided little or no additional benefit. As shown, the amount of coke plateaued at slightly above 1 wt%. For the bitumen sample lacking oil sands particles, 300 wppm or more of Mo catalyst was needed to suppress coke formation and reach the plateau level. The bitumen sample contain oil sands particles at 1.3 wt% reduced the amount of Mo catalyst that was needed to suppress coke formation and reach the plateau level. As shown, only about 150 wppm of the Mo catalyst was needed to reach the plateau level in the presence of the oil sands particles. At lower catalyst loading values, the clay particles suppressed the formation of coke relative to the bitumen alone.

[0146] As a comparison sample, the clay particles recovered from the Athabasca bitumen were added at 3 wt% to the solids-free Cold Lake bitumen. The comparison sample exhibited a similar amount of coke formation to the Athabasca bitumen at a Mo catalyst loading of 150 ppm. This result shows that the solids are the likely source of the lower coke yield, rather than due to compositional differences between the two bitumen sources. Therefore, it can be concluded that bitumen containing indigenous clay particles has lower coking tendency that bitumen without particles. As show, the clay particles may suppress coke formation as demonstrated by lower the Mo concentration needed to reach the coke plateau.

[0147] FIG. 6 is a graph of product composition obtained during slurry hydroprocessing as function of catalyst loading in the presence of oil sands fines. For the data in FIG. 6, the feed was an Athabasca bitumen (850°F+ (454.4°C+) bitumen fraction) processed by a naphthenic froth treatment to leave behind residual clay particles (0.9 wt% in this case). The slurry hydroprocessing conditions included exposing the feed to 3000 psig of H2 in a batch reactor for 3 hours at a temperature of 830°F (~445°C). This resulted in roughly 80 wt% conversion of the feed. As shown in FIG. 6, the minimum (plateau) level of coke formation (again, roughly 1.0 wt%) was achieved using approximately 20-40 wppm or more of Mo catalyst. This result demonstrates that when oil sand fines are present, at sufficiently high hydrogen pressures, the amount of Mo catalystneeded for effective slurry hydroprocessing may be further decreased such that little or possibly even no conventional slurry hydroprocessing catalyst is needed to achieve desirable results.

[0148] FIG. 6 also shows the sulfur content and the Conradson Carbon Residue content of the slurry hydroprocessing effluent. As shown, the amount of Conradson Carbon Residue in the effluent varied with the amount of additional Mo catalyst in a manner similar to the level of coke formation, with a plateau value eventually being reached using roughly 20 wppm or more of Mo catalyst. By contrast, additional sulfur reduction was achieved by using 40 wppm or more of the Mo catalyst. Thus, the level of additional Mo catalyst that promotes sulfur removal down to a plateau value may be higher than the level of additional Mo catalyst that may be effective for suppressing coke formation and / or formation of Conradson Carbon Residue.

[0149] Accordingly, as shown in FIG. 6, very low amounts of Mo catalyst again may suppress coke formation when solids are present in the bitumen. Although coke formation plateaus at a low loading of Mo catalyst, higher Mo catalyst loadings may achieve other process objectives, such as lowering of residue carbon or decreasing the sulfur content.

[0150] FIG. 7 is a graph of coke formation obtained during slurry hydroprocessing as function of oil sands particle loading in lieu of a Mo catalyst. For the data in FIG. 7, the bitumens were obtained from two different sources to afford feeds defining a 850°F+ (454.4°C+) bitumen fraction. Bitumen #2 was particle-free as produced, and Bitumen #1 contained approximately 1 wt% clay particles as produced. As shown in FIG. 7, each sample was further doped with increasing loadings of additional oil sands clay particle solids obtained during a naphthenic froth treatment. No additional Mo catalyst was added. The slurry hydroprocessing conditions included exposing the feed to 2000-3500 psig of H in a batch reactor for 3 hours at a temperature of 83O°F (~445°C). As shown, coke formation decreased with increasing clay particle loading. Unlike a traditional Mo catalyst, the coke formation did not plateau over the range of particle loadings studied. Accordingly, at equivalent conditions and without any added solids, the bitumen with indigenous clay (Bitumen #1) has a much lower coke yield than the bitumen without indigenous solids (Bitumen #2), and adding additional solids further suppresses coke formation in both bitumens.

[0151] FIG. 8 is a graph of experimental particle settling rate as a function of solvent to bitumen ratio during an illustrative paraffinic froth treatment under various single-stage and two- stage separation conditions. Single-stage separations were performed by mixing the solvent into bitumen in a test tube at a solvent:bitumen ratio of 1.4 or above to precipitate solids. The precipitations were performed at 70°C or 90°C. Two-stage separations were performed by sieving out coarse solids from crude bitumen, so that the particle size distribution of the remaining bitumen might mimic that of froth overflow provided to a second stage. After removing coarse solids,additional solids were precipitated by adding water at a solvent:bitumen ratio of 1.1 -1.4. Two- stage separations were performed at 90°C.

[0152] As shown in FIG. 8, during a single-stage paraffinic froth treatment, the settling rate increased with temperature, albeit at a higher solvent to bitumen ratio at the higher temperature. In both cases, a solvent to bitumen ratio of 1.4 or greater was needed to achieve a commercially viable settling rate of 600 mm / min or more. Settling during the second stage of a paraffinic froth treatment was achieved at a lower solvent to bitumen ratio. As shown, the settling rates for the second-stage mixtures were substantially higher than the single-stage mixtures at a comparable solvent to bitumen ratio. Moreover, as shown in FIG. 8, the settling rate had little or no dependence on the amount of solids or water in the second stage. This data indicates that the removal of coarse solids in the initial stage of the paraffinic froth treatment is related to the improved settling rate.

[0153] FIG. 9 is a graph of asphaltenes content as function of solvent to bitumen ratio during an illustrative paraffinic froth treatment. The data shown corresponds to selected samples from FIG. 8. As shown, the amount of asphaltenes is primarily dependent on the solvent to bitumen ratio, regardless of whether a single-stage or a multiple-stage paraffinic froth treatment process is used. In view of FIGS. 8 and 9, a lower solvent to bitumen ratio may afford a synergistic combination of both increased settling rate and greater retention of asphaltenes in the resulting bitumen. FIG. 10 is a graph of settling rate as function of asphaltenes content during an illustrative paraffinic froth treatment. The data shown corresponds to the samples from FIG. 9. As shown in FIG. 10, the asphaltenes content for the bitumen formed using the multi-stage paraffinic froth treatment was substantially higher relative to the settling rate.

[0154] The settling rate is related to the volumetric throughput per area of the settler vessel. Based on this relationship, FIG. 11 provides another way of viewing the data shown in FIG. 10. FIG. 11 is a graph of volumetric throughput for single-stage and multi-stage paraffinic froth treatments as a function of bitumen recovery. As shown, given the higher asphaltene retention in the two-stage process, bitumen recovery is primarily influenced by retention of asphaltenes in the bitumen. Thus, the faster settling rate that can be achieved using a multi-stage paraffinic froth treatment allows for greater volumetric throughput at a given level of bitumen recovery.

[0155] When numerical lower limits and numerical upper limits are listed herein, ranges from any lower limit to any upper limit are contemplated. While the illustrative embodiments of the invention have been described with particularity, it will be understood that various other modifications will be apparent to and can be readily made by those skilled in the art without departing from the spirit and scope of the invention. Accordingly, it is not intended that the scope of the claims appended hereto be limited to the examples and descriptions set forth herein but ratherthat the claims be construed as encompassing all the features of patentable novelty which reside in the present invention, including all features which would be treated as equivalents thereof by those skilled in the art to which the invention pertains.

[0156] The present invention has been described above with reference to numerous embodiments and specific examples. Many variations will suggest themselves to those skilled in this art in light of the above detailed description. All such obvious variations are within the full intended scope of the appended claims.

[0157] All documents described herein are incorporated by reference herein for purposes of all jurisdictions where such practice is allowed, including any priority documents and / or testing procedures to the extent they are not inconsistent with this text. As is apparent from the foregoing general description and the specific embodiments, while forms of the disclosure have been illustrated and described, various modifications can be made without departing from the spirit and scope of the disclosure. Accordingly, it is not intended that the disclosure be limited thereby. For example, the compositions described herein may be free of any component, or composition not expressly recited or disclosed herein. Any method may lack any step not recited or disclosed herein. Likewise, the term “comprising” is considered synonymous with the term “including.” Whenever a method, composition, element or group of elements is preceded with the transitional phrase “comprising,” it is understood that we also contemplate the same composition or group of elements with transitional phrases “consisting essentially of,” “consisting of,” “selected from the group of consisting of,” or “is” preceding the recitation of the composition, element, or elements and vice versa.

[0158] Unless otherwise indicated, all numbers expressing quantities of ingredients, properties such as molecular weight, reaction conditions, and so forth used in the present specification and associated claims are to be understood as being modified in all instances by the term “about.” Accordingly, unless indicated to the contrary, the numerical parameters set forth in the following specification and attached claims are approximations that may vary depending upon the desired properties sought to be obtained by one or more embodiments described herein. At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the scope of the claim, each numerical parameter should at least be construed in light of the number of reported significant digits and by applying ordinary rounding techniques.

[0159] Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forthevery number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces.

[0160] One or more illustrative embodiments are presented herein. Not all features of a physical implementation are described or shown in this application for the sake of clarity. It is understood that in the development of a physical embodiment of the present disclosure, numerous implementation- specific decisions must be made to achieve the developer's goals, such as compliance with system-related, business-related, government-related and other constraints, which vary by implementation and from time to time. While a developer's efforts might be time- consuming, such efforts would be, nevertheless, a routine undertaking for one of ordinary skill in the art and having benefit of this disclosure.

[0161] Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practiced in different but equivalent manners apparent to one having ordinary skill in the art and having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope and spirit of the present disclosure. The embodiments illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and / or any optional element disclosed herein.

Claims

CLAIMSWhat is claimed is the following:

1. A method for upgrading oil sands, comprising: exposing oil sands to a water extraction process to form a froth, the oil sands comprising particles and asphaltenes; adding a paraffinic froth solvent to the froth under froth treatment conditions to form a bitumen comprising 0.05 wt% or more particles, based upon total mass of the bitumen; wherein about 80 wt% or more of the asphaltenes from the oil sands are retained in the bitumen; and exposing at least a portion of the bitumen obtained from the froth treatment conditions to slurry hydroprocessing conditions in a slurry hydroprocessing reactor in the presence of the particles to form a light ends fraction, a slurry hydroprocessing effluent, and a pitch fraction, the slurry hydroprocessing conditions affording 90% conversion or less of the bitumen to 566°C.

2. The method of claim 1, wherein exposing at least a portion of the bitumen to slurry hydroprocessing conditions comprises: performing a boiling point separation on at least a portion of the bitumen to form a lower boiling fraction and a higher boiling fraction; and exposing at least a portion of the higher boiling fraction to the slurry hydroprocessing conditions.

3. The method of claim 2, wherein performing a boiling point separation comprises: separating the at least a portion of the bitumen under atmospheric separation conditions to form at least an atmospheric bottoms fraction, a fraction comprising the paraffinic froth solvent, and one or more additional fractions comprising 343 °C- compounds, the bitumen having an API gravity of 15° or less; and separating at least a portion of the atmospheric bottoms fraction under vacuum separation conditions to form at least a vacuum bottoms fraction and one or more vacuum gas oil fractions, the vacuum bottoms fraction comprising the particles.

4. The method of any one of claims 1-3, wherein exposing at least a portion of the bitumen to slurry hydroprocessing conditions comprises: performing solvent deasphalting on at least a portion of the bitumen to form deasphalted oil and deasphalter rock; and exposing at least a portion of the deasphalter rock to the slurry hydroprocessing conditions.

5. The method of claim 4, wherein solvent deasphalting is performed on a bottoms fraction obtained from a boiling point separation.

6. The method of any one of claims 1-5, wherein the froth treatment conditions comprise adding the paraffinic froth solvent at a temperature of 85°C or more, adding the paraffinic froth solvent at a weight ratio of paraffinic froth solvent to bitumen of 1.3 or less, or a combination thereof.

7. The method of any one of claims 1-6, wherein the bitumen has an API gravity of 15° or less.

8. The method of any one of claims 1-7, wherein the water extraction process comprises a hot water extraction process, the hot water having a temperature of about 80°C to about 85 °C.

9. The method of any one of claims 1-8, wherein the at least a portion of the bitumen is exposed to the slurry hydroprocessing conditions in the presence of 10 wppm to 500 wppm of an additional catalyst comprising a catalytically active metal.

10. The method of claim 9, wherein the catalytically active metal comprises molybdenum.

11. The method of any one of claims 1-8, wherein an additional catalyst is not present when the at least a portion of the bitumen is exposed to the slurry hydroprocessing conditions.

12. The method of any one of claims 1-11, wherein the paraffinic froth solvent comprises Cs to Cs alkanes.

13. The method of any one of claims 1-12, wherein the bitumen is separated from the paraffinic froth solvent to form a fraction comprising 50 vol% or more of the paraffinic froth solvent.

14. The method of claim 13, further comprising: recycling at least a portion of the fraction comprising 50 vol% or more of the paraffinic froth solvent to provide at least a portion of the paraffinic froth solvent added to the froth.

15. The method of any one of claims 1-14, wherein the slurry hydroprocessing conditions produce a single-pass conversion of 50 wt% or less relative to 566°C.

16. The method of any one of claims 1-15, further comprising: exposing at least a portion of the pitch fraction to partial oxidation conditions.

17. The method of any one of claims 1-16, wherein the bitumen comprises about 15 wt% to about 18 wt% asphaltenes.

18. The method of any one of claims 1-17, wherein the bitumen comprises 0.05 wt% to 10 wt% particles, based on a total mass of the bitumen.

19. The method of any one of claims 1-18, wherein the bitumen comprises 0.05 wt% to 0.5 wt. % particles, based on a total mass of the bitumen.

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