Patent Application
20250066675
The disclosure relates generally to the field of oil sand processing, and more particularly to heavy hydrocarbon feedstock upgrading.
This section is intended to introduce various aspects of the art, which may be associated with the present disclosure. This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure. Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art.
Modern society is greatly dependent on the use of hydrocarbon resources for fuels and chemical feedstocks. Hydrocarbons are generally found in subsurface formations that can be termed “reservoirs”. Removing hydrocarbons from the reservoirs depends on numerous physical properties of the subsurface formations, such as the permeability of the rock containing the hydrocarbons, the ability of the hydrocarbons to flow through the subsurface formations, and the proportion of hydrocarbons present, among other things. Easily harvested sources of hydrocarbons are dwindling, leaving less accessible sources to satisfy future energy needs. As the costs of hydrocarbons increase, the less accessible sources become more economically attractive.
Recently, the harvesting of oil sand to remove heavy oil has become more economical. Hydrocarbon removal from oil sand may be performed by several techniques. For example, a well can be drilled to an oil sand reservoir and steam, hot air, solvents, or a combination thereof, can be injected to release the hydrocarbons. The released hydrocarbons may be collected by wells and brought to the surface. In another technique, strip or surface mining may be performed to access the oil sand, which can be treated with water, steam or solvents to extract the heavy oil.
Oil sand extraction processes are used to liberate and separate bitumen from oil sand so that the bitumen can be further processed to produce synthetic crude oil or mixed with diluent to form “dilbit” and be transported to a refinery plant. Numerous oil sand extraction processes have been developed and commercialized, many of which involve the use of water as a processing medium. Where the oil sand is treated with water, the technique may be referred to as water-based extraction (WBE) or as a water-based oil sand extraction process. WBE is a commonly used process to extract bitumen from mined oil sand.
One WBE process is the Clark hot water extraction process (the “Clark Process”). This process typically requires that mined oil sand be conditioned for extraction by being crushed to a desired lump size and then combined with hot water and perhaps other agents to form a conditioned slurry of water and crushed oil sand. In the Clark Process, an amount of sodium hydroxide (caustic) may be added to the slurry to increase the slurry pH, which enhances the liberation and separation of bitumen from the oil sand. Other WBE processes may use other temperatures and may include other conditioning agents, which are added to the oil sand slurry, or may operate without conditioning agents. This slurry is first processed in a Primary Separation Cell (PSC), also known as a Primary Separation Vessel (PSV), to extract the bitumen from the slurry.
In one WBE process, a water and oil sand slurry is separated into three major streams in the PSC: bitumen froth, middlings, and a PSC underflow (also referred to as coarse sand tailings (CST)).
Regardless of the type of WBE process employed, the process will typically result in the production of a bitumen froth that requires treatment with a solvent. For example, in the Clark Process, a bitumen froth stream comprises bitumen, solids, and water. Certain processes use naphtha to dilute bitumen froth before separating the product bitumen by centrifugation. These processes are called naphtha froth treatment (NFT) processes. Other processes use a paraffinic solvent, and are called paraffinic froth treatment (PFT) processes, to produce pipelineable bitumen with low levels of solids and water. In the PFT process, a paraffinic solvent is used to dilute the froth before separating the product, diluted bitumen, by gravity. A portion of the asphaltenes in the bitumen is also rejected by design in the PFT process and this rejection is used to achieve reduced solids and water levels. In both the NFT and the PFT processes, the diluted tailings (comprising water, solids and some hydrocarbon) are separated from the diluted product bitumen.
Solvent is typically recovered from the diluted product bitumen component before the bitumen is delivered to a refining facility for further processing.
The PFT process may comprise at least three units: Froth Separation Unit (FSU), Solvent Recovery Unit (SRU) and Tailings Solvent Recovery Unit (TSRU). Mixing of the solvent with the feed bitumen froth may be carried out counter-currently in two stages in separate froth separation units. The bitumen froth comprises bitumen, water, and solids. A typical composition of bitumen froth is about 60 wt. % bitumen, 30 wt. % water, and 10 wt. % solids. The paraffinic solvent is used to dilute the froth before separating the product bitumen by gravity. The foregoing is only an example of a PFT process and the values are provided by way of example only. An example of a PFT process is described in Canadian Patent No. 2,587,166 to Sury.
From the PSC, the middlings, which may comprise bitumen and about 10-30 wt. % solids, or about 20-25 wt. % solids, based on the total wt. % of the middlings, is withdrawn and sent to the flotation cells to further recover bitumen. The middlings are processed by bubbling air through the slurry and creating a bitumen froth, which is recycled back to the PSC. Flotation tailings (FT) from the flotation cells, comprising mostly solids and water, are sent for further treatment or disposed in an external tailings area (ETA).
Oil sands bitumen produced in Western Canada is extremely viscous (viscosity >100,000 cSt) and requires blending with a substantial amount of diluent (25-40 volume %) to meet pipeline viscosity specification. Diluent addition represents a significant cost to bitumen producers. Due to the significant cost of diluent, as well as the bitumen/diluent (dilbit) blend's quality debit, partial upgrading of bitumen is desirable.
By definition, ‘full’ bitumen upgrading entails converting bitumen (via thermal or catalytic process, such as coking, hydrocracking, fluid catalytic cracking (FCC), etc.) into synthetic crude oil (SCO), which contains no resid (1050° F.+) boiling range molecules. ‘Partial’ upgrading, on the other hand, is defined as any combination of processing steps to convert bitumen/heavy oil to an oil product with sufficient fluidity to enable pipeline transport with significantly reduced (or no) diluent addition.
Table 1 provides pipeline specifications to transport crude oil from Alberta.
Bitumen has an extremely low H/C ratio and can have up to 50% resid (1050 F+) fraction. Carbon rejection methods (e.g. coking, deasphalting) are proven for upgrading, but come with challenges (e.g. lower liquid yields). Hydrogen addition methods (e.g. fixed-bed hydro-processing, slurry hydrocracking), on the other hand, increase yields but are expensive and require H2 production and sulfur management facilities. These ancillary processes can cause upgrading to be economically infeasible (due to higher capital). Therefore, while full/partial upgrading provides significant quality uplift and produces a lower viscosity and density crude oil, the costs association with building an upgrader may be high or prohibitive. Thus, there remains a need for alternative methods of upgrading bitumen.
In one aspect, the present disclosure provides a process that includes: providing bitumen; performing thermal upgrading on the bitumen to form mildly upgraded bitumen; distilling the mildly upgraded bitumen to form streams of naphtha; distillates and/or gas oils; and residue; combining the naphtha and residue to form a naphtha/residue stream, which causes deasphalting to occur, and forming streams of deasphalted oil and high-carbon pitch comprising asphaltenes; and adding the distillates and/or gas oils to the deasphalted oil to form partially upgraded bitumen. Combining the naphtha and residue to form a naphtha/residue stream may include adding an external solvent to facilitate the deasphalting process.
The thermal upgrading may be performed at the following conditions: a temperature of 400-550° C., a residence time of 10-120 minutes, and a pressure of 50-1500 psig.
The distilling may occur at cuts of less than 270° C. and greater than 400° C.
The partially upgraded bitumen may meet pipeline specifications.
The partially upgraded bitumen may have a viscosity of less than or equal to 350 cSt at pipeline temperature, a density of less than or equal to 940 kg/m3, an API gravity greater than or equal to 19, a base sediment and water content of less than 0.5 vol. %, and an olefin content of less than 1 wt. %.
The partially upgraded bitumen may require from 0 to 15 vol % of diluent to meet pipeline specifications.
The process may further include converting the high-carbon pitch to a carbon product. The carbon product may include carbon fiber, carbon-carbon-composite, carbon foam, graphene, graphite, or petroleum coke.
The deasphalting may be performed at the following conditions: a temperature of 100° C. to 350° C., a pressure of 100-1000 psig, and a naphtha to residue ratio of 0.5:1 to 4:1.
In another aspect, the present disclosure provides a process that includes: providing dilbit; performing thermal upgrading on the dilbit to form mildly upgraded dilbit; distilling the mildly upgraded dilbit to form a light stream and streams of distillates and/or gas oils; and residue; separating the light stream into diluent and a second light stream; hydropolishing the second light stream to form naphtha; combining the naphtha and residue to form a naphtha/residue stream, which causes deasphalting to occur, and forming streams of deasphalted oil and high-carbon pitch comprising asphaltenes; and adding the distillates and/or gas oils to the deasphalted oil to form partially upgraded bitumen.
The thermal upgrading may include conditions of a temperature of 400-550 C, a residence time of 10-120 minutes, and a pressure of 50-1500 psig.
The process may further include converting the high-carbon pitch to a carbon product. The carbon product may include carbon fiber, carbon-carbon-composite, carbon foam, graphene, graphite, or petroleum coke.
Combining the naphtha and residue to form a naphtha/residue stream may include adding an external solvent to facilitate the deasphalting process.
The foregoing has broadly outlined the features of the present disclosure so that the detailed description that follows may be better understood. Additional features will also be described herein.
These and other features, aspects and advantages of the disclosure will become apparent from the following description, appending claims and the accompanying drawing, which is briefly described below.
It should be noted that these figures are merely examples and no limitations on the scope of the present disclosure is intended thereby. Further, the figures are generally not drawn to scale, but are drafted for purposes of convenience and clarity in illustrating various aspects of the disclosure.
For the purpose of promoting an understanding of the principles of the disclosure, reference will now be made to the features illustrated in the drawings and specific language will be used to describe the same. It will nevertheless be understood that no limitation of the scope of the disclosure is thereby intended. Any alterations and further modifications, and any further applications of the principles of the disclosure as described herein are contemplated as would normally occur to one skilled in the art to which the disclosure relates. It will be apparent to those skilled in the relevant art that some features that are not relevant to the present disclosure may not be shown in the drawings for the sake of clarity.
At the outset, for ease of reference, certain terms used in this application and their meaning as used in this context are set forth below. To the extent a term used herein is not defined below, it should be given the broadest definition persons in the pertinent art have given that term as reflected in at least one printed publication or issued patent. Further, the present processes are not limited by the usage of the terms shown below, as all equivalents, synonyms, new developments and terms or processes that serve the same or a similar purpose are considered to be within the scope of the present disclosure.
Throughout this disclosure, where a range is used, any number between or inclusive of the range is implied.
A “hydrocarbon” is an organic compound that primarily includes the elements of hydrogen and carbon, although nitrogen, sulfur, oxygen, metals, or any number of other elements may be present in small amounts. Hydrocarbons generally refer to components found in heavy oil or in oil sand. However, the techniques described are not limited to heavy oils but may also be used with any number of other reservoirs to improve gravity drainage of liquids. Hydrocarbon compounds may be aliphatic or aromatic, and may be straight chained, branched, or partially or fully cyclic.
“Bitumen” is a naturally occurring heavy oil material. Generally, it is the hydrocarbon component found in oil sand. Bitumen can vary in composition depending upon the degree of loss of more volatile components. It can vary from a very viscous, tar-like, semi-solid material to solid forms. The hydrocarbon types found in bitumen can include aliphatics, aromatics, resins, and asphaltenes. A typical bitumen might be composed of:
“Heavy oil” includes oils which are classified by the American Petroleum Institute (“API”), as heavy oils, extra heavy oils, or bitumens. The term “heavy oil” includes bitumen as well as lighter materials that may be found in a sand or carbonate reservoir. Heavy oil may have a viscosity of about 1,000 centipoise (cP) or more, 10,000 cP or more, 100,000 cP or more, or 1,000,000 cP or more. In general, a heavy oil has an API gravity between 22.3° API (density of 920 kilograms per meter cubed (kg/m3) or 0.920 grams per centimeter cubed (g/cm3)) and 10.0° API (density of 1,000 kg/m3 or 1 g/cm3). An extra heavy oil, in general, has an API gravity of less than 10.0° API (density greater than 1,000 kg/m3 or 1 g/cm3). For example, a source of heavy oil includes oil sand or bituminous sand, which is a combination of clay, sand, water and bitumen.
“Fine particles” or “fines” are generally defined as those solids having a size of less than 44 microns (μm), as determined by laser diffraction particle size measurement.
“Coarse particles” are generally defined as those solids having a size of greater than 44 microns (μm).
The term “solvent” as used in the present disclosure should be understood to mean either a single solvent, or a combination of solvents.
The terms “approximately,” “about,” “substantially,” and similar terms are intended to have a broad meaning in harmony with the common and accepted usage by those of ordinary skill in the art to which the subject matter of this disclosure pertains. It should be understood by those of skill in the art who review this disclosure that these terms are intended to allow a description of certain features described and claimed without restricting the scope of these features to the precise numeral ranges provided. Accordingly, these terms should be interpreted as indicating that insubstantial or inconsequential modifications or alterations of the subject matter described and are considered to be within the scope of the disclosure.
The articles “the”, “a” and “an” are not necessarily limited to mean only one, but rather are inclusive and open ended so as to include, optionally, multiple such elements.
Thermal upgrading of bitumen (visbreaking) may be a cost-effective approach to partial upgrading and is less expensive than alternative bitumen/heavy oil conversion processes such coking and slurry hydrocracking. Visbreaking occurs at moderately low temperatures (<500° C.) and is used to reduce or “break” the viscosity of oil. Commercially, visbreaking units operate to a liquid product quality limit, i.e. solids specification limit of 300 ppm. In the context of bitumen upgrading, however, there is no reason why visbreaking operating severity should be limited to meet this specification, so long as the solids are removed to fulfill the sediment & water specification of 0.5 vol % in crude oil for pipeline transportation.
The process may comprise partially upgrading bitumen via a thermal cracker (visbreaker) while minimizing processing units and reducing costs/capital. Using an inexpensive and available heavy oil/resid upgrading technology (i.e. visbreaking) may provide a higher value upgraded product with little to no diluent required for pipeline transport at significantly lower cost relative to other partial upgraders. While operating a visbreaker at typical conditions would limit bitumen conversion, the process may involve increasing visbreaking severity (via increase in temperature and/or residence time) to a point that would approach the thermal instability/incompatibility limit of the liquid product. The liquid product may then be distilled to produce at least three (3) boiling point cuts, including a naphtha fraction (Initial boiling point (IBP)-270° C.), one or more distillate/vacuum gas oil (VGO) fractions (270-565° C.), and a resid cut (565° C.+). Following distillation, the lightest (naphtha) and heaviest (resid) fractions may be blended together in a vessel that may be similar in design to a deasphalting unit. The naphtha fraction effectively acts as the deasphalting ‘solvent’ when blended with the resid fraction (which is already at the point of instability). This blending results in asphaltene precipitation, which would (1) further upgrade the resid, and (2) eliminate (or mitigate) solids created during the high severity visbreaking step. The ‘deasphalted oil’ (DAO) from this deasphalting step would be recovered and blended in with the distillate/VGO fraction generated in the distillation step to produce a partially upgraded bitumen (PUB), with a significantly lower viscosity and density than PFT bitumen, requiring little to no diluent for pipeline transport. Table 1 provides pipeline specifications to transport crude oil from Alberta. The rejected asphaltenes or ‘pitch’ from the deasphalting process may be recovered as petroleum coke, or as a solid to be used to manufacture non-combustion based carbon products, including carbon fiber, carbon-carbon composites, and carbon foams. This process may produce high PUB yield, since the amount of rejected pitch may be lower (e.g. <10 wt %) than conventional deasphalting.
The cost of the process may be lower than partial upgrading processes being considered that use thermal cracking and deasphalting. This is because the process may not require an external deasphalting solvent (which is typically 6-8× volume of bitumen feed) and the facilities associated with its storage or a solvent recovery unit, since the naphtha remains part of the final PUB blend. It also does not require a diluent recovery unit (DRU) on the front-end of the upgrading process, since dilbit (underblend) can be processed and the diluent recovered in the visbreaker fractionator. Avoiding or minimizing the use of external solvent also reduces the size of the vessel/process unit in which the deasphalting would occur. The elimination of multiple processing units may reduce overall footprint and CAPEX.
The process may partially upgrade bitumen to improve its quality and eliminate/reduce diluent for pipeline transport at reduced costs/capital. The process may also generate a high-carbon stream that is a precursor for the manufacturing of non-combustion materials, including carbon fibre. The process may involve using an inexpensive and available heavy oil/resid upgrading technology (i.e. visbreaking) to produce a higher value upgraded product with little to no diluent required for pipeline transport. Since bitumen conversion via typical visbreaking conditions is limited, the process may involve increasing visbreaking severity to the point of nearly achieving liquid product instability. The liquid product may be distilled to generate at least three fractions, including light naphtha, middle distillates/VGO heart-cut, and heavy resid cut. The naphtha and resid fractions may be re-blended together without the intermediate fractions to cause precipitation of the unstable molecules (i.e. asphaltenes), thereby further upgrading the resid. The rejected asphaltenes may be recovered as high-carbon pitch. The deasphalted resid/naphtha may then recombined with the distillate/VGO fraction to produce a partially upgraded bitumen, while the recovered pitch may be used to manufacture non-combustion based carbon products.
With reference to
Combining the naphtha and residue to form a naphtha/residue stream may include adding an external solvent to facilitate the deasphalting process.
The thermal upgrading may be performed at any suitable conditions, for example at the following conditions: a temperature of 400-550° C., a residence time of 10-120 minutes, and a pressure of 50-1500 psig.
The distilling may occur at any suitable cuts, for example at less than 270° C. and greater than 400° C.
The partially upgraded bitumen may meet pipeline specifications. The partially upgraded bitumen may have a viscosity of less than or equal to 350 cSt at pipeline temperature, a density of less than or equal to 940 kg/m3, an API gravity greater than or equal to 19, a base sediment and water content of less than 0.5 vol. %, and an olefin content of less than 1 wt. %.
The partially upgraded bitumen may require from 0 to 15 vol % of diluent to meet pipeline specifications. That is, the partially upgraded bitumen may require no diluent, or may require up to 15 vol. % diluent.
The high-carbon pitch may be converted to a carbon product. The carbon product may comprise carbon fiber, carbon-carbon-composite, carbon foam, graphene, graphite, or petroleum coke.
The deasphalting may be performed at any suitable conditions, for example at the following conditions: a temperature of 100° C. to 350° C., a pressure of 100-1000 psig, and a naphtha to residue ratio of 0.5:1 to 4:1.
The feed may be dilbit instead of bitumen. With reference to
Combining the naphtha and residue to form a naphtha/residue stream may include adding an external solvent to facilitate the deasphalting process.
Diluted bitumen or bitumen feed may be thermally cracked in a visbreaking unit at temperatures ranging from 400-550° C., residence times ranging from 10-120 minutes, and pressures ranging from 50-1500 psig. The total liquid product may be recovered and distilled to generate multiple fractions, including a naphtha fraction at a temperature of 270° C. or less and a resid fraction at a temperature of 400° C. or greater. A portion of the naphtha fraction may or may not be hydrotreated/hydropolished and may be recombined with the resid fraction alone or with external solvent in a unit that operates at a temperature range of 100-350° C., pressure range of 100-1000 psig, and naphtha-to-resid ratio ranging from 0.5:1 to 4:1. Additional “external” solvent, comprising propane, butane, pentane or a mixture of any of these hydrocarbons, may be added at a ratio ranging from 0:1 to 2:1 to supplement the naphtha being added to the resid fraction. If this supplemental “external” solvent is added, a solvent recovery unit to recover this solvent may be incorporated into the process. The addition of naphtha with/without external solvent and resid would cause the rejection of carbon material to take place. The carbon material may be used as precursor/feedstock to produce carbon-based products, including carbon fibre, graphenes, etc. The remaining liquid component of the naphtha/residue mixture may be blended back with the remaining fractions generated from the distillation to generate a partially upgraded bitumen.
A pilot plant experiment was run under the following conditions: thermal cracking of diluted bitumen at 435° C. for 75 min, distillation to generate 4 fractions, with cut temperatures as follows: Fraction 1 (naphtha): Initial boiling point (IBP)—182° C., Fraction 2: 182-343° C., Fraction 3:343-565° C., Fraction 4 (resid): 565° C.—final boiling point (FBP), deasphalting conducted at 230° C., with a naphtha-to-resid ratio of 1.5:1, no external solvent used. The results are shown in Table 2. As can be seen from Table 2, the produced PUB met all pipeline specifications.
It should be understood that numerous changes, modifications, and alternatives to the preceding disclosure can be made without departing from the scope of the disclosure. The preceding description, therefore, is not meant to limit the scope of the disclosure. Rather, the scope of the disclosure is to be determined only by the appended claims and their equivalents. It is also contemplated that structures and features in the present examples can be altered, rearranged, substituted, deleted, duplicated, combined, or added to each other. The scope of the claims should not be limited by particular embodiments set forth herein, but should be construed in a manner consistent with the specification as a whole.
This application claims the benefit of U.S. Provisional Application Ser. No. 63/578,905, entitled “Bitumen Upgrading and Carbon Product Production” filed Aug. 25, 2023, the disclosure of which is hereby incorporated by reference in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 63578905 | Aug 2023 | US |
