Simulation of bitumen upgrading processes

Two bitumen upgrading processes currently used in the Canadian oil sands industry were investigated using modelling and simulation techniques


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Article Summary

The Canadian oil sands industry currently produces about 1.6 million barrels of combined mining and in-situ-based bitumen. About 55% of it is upgraded to synthetic crude oil (SCO) and then processed in Canadian and US refineries.1 The production of transportation fuels from Canadian bitumen requires either new, integrated upgrading and refining facilities, or the updating of existing refineries that use conventional crudes to allow more input of bitumen feedstocks.2 In either case, it is important and useful to model and simulate the entire upgrading and refining scheme under different process configurations and product scenarios, to minimise process-related energy intensity while achieving the best economic benefits. This can provide guidelines to existing upgrading and refining operations as well as to process design for new upgraders and refineries.

There are two major primary bitumen upgrading technologies: coking and hydroconversion.3,4 Historically, coking has predominated as the choice for primary upgrading.5 As the first step to producing a bottomless (zero residue) SCO, it handles easily the higher solids and water contents in mining-based bitumen. The byproduct coke helps to trap solids, as well as concentrate and remove metals, and some of the sulphur and nitrogen contained in bitumen. However, the total liquid product yield is relatively low due to coke formation.6 In comparison, ebullated-bed catalytic hydroconversion is more selective towards a total liquid yield due to hydrogen addition.7 In commercial operations, the conversion of bitumen is not 100% in the hydroconversion unit, generating a small portion of residue that is either further processed in a coking unit or withdrawn as byproduct. Therefore, bitumen upgraders currently use either coking or ebullated-bed hydroconversion, or a combination of both.8
Both of the two primary upgrading processes produce liquid products with boiling ranges similar to those of conventional crudes. However, they have high concentrations of impurities, such as sulphur and nitrogen.9 The downstream hydrotreating units remove these impurities to produce sweet blending feedstocks for SCO without changing the boiling range of the liquid too much. The SCO boiling range is essentially controlled by the primary upgrading step. In reviewing some of the major challenges that the oil sands industry is facing, bitumen upgraders need to capitalise on, or address, the following:
• Take advantage of some relatively minor upgrading at the recovery stage
• Take advantage of the necessity to move to alternative energy and hydrogen sources, particularly internally generated residues, which may greatly influence the selection of the main upgrading process
• Address major environmental and greenhouse gas (GHG) emission concerns in an integrated way
• Improve SCO quality with existing facilities.

The oil sands industry is, by its very nature, in a position to influence technology development for its relatively unique needs. It is important to identify the possible avenues for better upgrading technology for current and future projects.10 While some new primary upgrading technologies are being developed and implemented, such as slurry-phase hydrocracking and supercritical solvent extraction/deasphalting, the existing commercial processes and technologies — namely, coking, ebullated-bed hydroconversion, hydrotreating and hydrocracking — will still dominate for the foreseeable future.4 Therefore, modelling, simulation and optimisation of these integrated processes will provide valuable and helpful knowledge towards innovative process design and operation.  

The objective of this study is to evaluate commercial bitumen upgrading schemes by performing process modelling and simulation, which will help the industry to improve process efficiency, reduce GHGs emissions and other related environmental impacts (for instance, optimised H2 and water use) in future bitumen upgrading and refining schemes.

Bitumen upgrading process
Figure 1 presents a generic flow diagram of the bitumen upgrading process. The diluted bitumen from extraction and froth treatment plant first passes through the diluent recovery unit (DRU), where the diluent is recovered and recycled to the extraction plant. The atmospheric-topped bitumen (ATB) is fed to a vacuum distillation unit (VDU) to obtain naphtha, light gas oil (LGO), heavy gas oil (HGO) and vacuum-topped bitumen (VTB). The VTB is processed either in a coker unit or in an ebullated-bed hydroconversion reactor, or even in both. The total liquid product (TLP) from the coking and/or hydroconversion stage is fractionated, and the resulting streams are combined with the corresponding fractions coming from the VDU and routed separately to hydrotreating (HDT) units. After hydrotreating, these streams are blended to form SCO, which is transported by pipeline to refineries in Canada and the US.

Modelling and simulation approach
The simulation was conducted in the Aspen Hysys environment. Two typical bitumen upgrading schemes were analysed: coking and hydroconversion based. Oil properties of interest (API gravity, sulphur, nitrogen and metals, among others) and product yield shifts at every conversion step were handled by the Petroleum Refining tool in Hysys. Since Hysys does not have modules for certain units of the bitumen upgrading scheme —namely, coker, ebullated-bed hydroconverter and naphtha hydrotreater — kinetic models were developed and implemented into Hysys to predict the performance of those processes, as will be discussed below. Other units, such as distillation columns and gas oil hydrotreaters, were simulated with built-in Hysys modules. All of the units were carefully calibrated based on in-house experimental data and published data.6-18

Coking and hydroconversion kinetics were formulated based on simple reaction networks involving the following lumps: gas (C1-C4, H2S and NH3), naphtha (IBP-204°C), LGO (204-343°C), HGO (343- 524°C), vacuum residue (524C°+) and coke (for the coker unit only). The hydroconversion model also included hydrodesulphurisation (HDS), hydrodenitrogenation (HDN), hydrodemetallisation (HDM) and hydrogen consumption. The rate equations accounted for the effect of temperature and pressure in the case of hydroconversion, whereas they were only temperature dependent in the case of coking. The models were properly tuned and implemented in a Hysys spreadsheet. This feature enables user-defined calculations to be performed using any variable from the simulation flowsheet and then the results exported to any stream or unit. In this case, the spreadsheet imported the operating conditions from the feed stream to calculate the product distribution. The yield shift was then performed by the Petroleum Shift Reactor tool using the product yield estimates as input. The effect of hydrotreating on the chemical composition and physical properties of the feed was handled by the Assay Manipulator. This tool adjusts the distribution of assay properties (such as sulphur content) along the entire boiling range by specifying a target bulk value, which is determined by hydrotreating kinetics.

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