Full conversion of bitumen
A line-up featuring ebullated bed hydrocracking delivers full conversion of bitumen, including production of premium diesel fuel
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Bitumen is commonly called ‘tar sands’ or ‘oil sands’. The world reserve of bitumen is about 5500 billion barrels of oil.1 Assuming that the current world consumption of crude oil is about 35 billion barrels per year,2 global reserves of bitumen potentially can supply the world with fuels for over 100 years. About 40% of the world’s bitumen reserves are in Canada (see Figure 1).1 Therefore, understanding how to refine bitumen into fuels for today’s market needs is a relevant topic to consider.
Bitumen can be more broadly defined as the fraction of large chemical aggregates in sedimentary organic matter that is soluble in solvents.3 The geological age of bitumen relative to crude oil may be younger or older than crude oil depending on how the bitumen is formed. The first instance of kerogen, or oil shale, maturation produces bitumen. However, studies1 conclude that bitumen from kerogen conversion accounts for a relatively small proportion of natural bitumen and heavy oils. The large abundance of kerogen and crude oil occurs from planktonic precursors, which are composed of fatty free acids and are relatively paraffinic. One theory suggests that heavy oils and bitumen are produced from the degradation of lighter, more paraffinic oils. The light, young oil is thought to be expelled from regions of higher pressure and temperature to lower pressure and temperature. Lower pressure zones may be at lesser depths with temperatures less than 80°C where bacteria can survive. Beyond this temperature limit, these bacteria die. The lighter paraffinic oil can be converted into the heavier oil or bitumen by water washing of soluble, lighter oil components, evaporation of lighter oil components and degradation of the lighter components by bacteria.1 These hypothesised geological processes all enrich the concentration of hetero-atomic sulphur, nitrogen and oxygen containing species and increase the concentration of heavier molecules such as resins and asphaltenes. The concentration of these heavier molecules also is a determining factor in the viscosity of crude oil or bitumen.
Figure 2 compares the true boiling point distillations of a Cold Lake Canadian bitumen without diluent4 with heavy, medium and light crude oils.6,7 The distillations exemplify the disappearance of lighter boiling components as the crude oils become heavier and eventually are transformed into bitumen. For example, Murban crude oil already contains 35 mass% of hydrocarbons boiling below the initial boiling point of Cold Lake bitumen. The densest and most viscous components are in the fraction of the oil or bitumen that boils above 565°C, which is commonly called vacuum residue. Light oil, such as Murban crude, may only contain 10 mass% residue7 compared with bitumen that contains about â€¨45 mass% residue.4
Table 1 compares some physical and chemical properties of a bitumen, a heavy crude oil, a medium crude oil and a light crude oil.5-7 For example, Canadian bitumen densities are about 0.99 to 1.02 specific gravity,5 whereas more typical medium and light crude oil densities vary from 0.82 to 0.92 specific gravity.6-7 The worldwide average produced crude density is about 0.82 specific gravity, or 41° API.2 The viscosity of bitumen is 100 to 1000 times higher than medium and light crude oils.5-7 The concentration of heteroatomic molecules containing sulphur, nitrogen, oxygen and metals can be significantly greater in bitumen compared with typical crude oils. Peregrino extra-heavy crude oil appears very similar to bitumen based on its distillation and physical and chemical properties.6
Bitumen can be two to three orders of magnitude higher in viscosity than heavy and ‘extra heavy’ oils (see Figure 3). Bitumen is typically immobile in its reservoir under the reservoir’s naturally occurring temperature. When bitumen is mobile in its reservoir, the bitumen may be considered to be extra heavy oil.1
Diluting bitumen with naphtha to make dilbit facilitates the transportation of bitumen to refineries by reducing the bitumen’s viscosity. The bitumen or a portion of it, such as the vacuum residue, can also be converted into synthetic crude oil or a synthetic crude component by performing an upgrading operation such as delayed coking followed by mild hydrotreatment. When a portion of bitumen is converted into a synthetic crude and blended with the remaining portion of bitumen, the blend is synbit.
North West Redwater Partnership processing objectives
North West Redwater Partnership (NWR) is a joint venture project between North West Refining Inc. and Canadian Natural Resources Ltd (CNRL). NWR is in the final stages of constructing the first of three phases of the Sturgeon refinery located near Redwater, Alberta. Unlike conventional bitumen upgrading companies that produce a synthetic crude oil product that requires further upgrading in downstream refineries, the NWR Sturgeon refinery will produce finished products, primarily ultra low sulphur diesels (ULSD) and other products such as LPG, diluent naphtha for sale to bitumen producers, and low sulphur vacuum gasoil (VGO) for sale to conventional refineries.
The NWR refinery will process both dilbit and synbit. The refining of bitumen at NWR is accomplished through the technologies shown in Figure 4.
The bitumen blends, either dilbit or synbit, are fractionated in a crude/vacuum distillation unit. The naphtha range material in the dilbit will be separated and sent to the diluent naphtha product pool. A straight-run diesel stream will be produced as a side draw from the crude column. The vacuum column produces light, medium and heavy VGO, and a vacuum residue stream. NWR upgrades the vacuum residue using ebullated bed hydrocracking technology as opposed to a non-catalytic, thermal technology such as delayed coking. Ebullated bed hydrocracking creates tremendous product margin advantage over delayed coking because ebullated bed hydrocracking does not create coke, reduces contaminants to downstream units, and adds hydrogen into the products, all of which substantially increase the volume swell of intermediate products for further refining. The ebullated bed hydrocracking unit converts the vacuum residue stream to naphtha, diesel, VGO (LVGO, MVGO, HVGO), boiling range hydrocarbons and unconverted pitch streams. Unconverted pitch will be gasified to produce hydrogen for the refinery. The NWR refinery is designed to sequester carbon dioxide from the gasifier and will provide captured carbon dioxide to a third party for enhanced oil recovery.
The molecular composition of bitumen typically contains higher concentrations of aromatics and cycloparaffins compared to conventional crude sources.8 Due to the high ring concentration in bitumen and synthetic components derived from bitumen, the saturation of aromatics leads to a high concentration of cycloparaffins in fuels products. The alkyl chains are relatively short on these cycloparaffins.8 The concentration of high cetane number n-paraffins is relatively low. In addition, hydrocracking of the VGO boiling range streams, primarily into distillate, performs limited ring opening and further isomerisation of the cracked products. All of these factors contribute to lower cetane numbers of distillates derived from bitumen or synbit relative to the cetane numbers obtained from conventional crude oil. All of these same factors, however, also lead to improved cold flow properties, which is essential for producing fuels for the Canadian and northern US markets.
Canadian industrial experience has shown that a heavy emphasis on installation of hydrocracking and hydroprocessing technologies is required to meet diesel fuel specifications when processing bitumen or bitumen-derived streams.8,9 The refining technology in the NWR Sturgeon refinery (see Figure 4) is based on 100% hydroprocessing to meet the stringent diesel fuel specifications shown in Table 2.
NWR selected Unicracking and Unionfining technologies to process the straight-run bitumen diesel and VGO streams and ebullated bed hydrocracking naphtha, diesel and VGO boiling range streams. NWR’s processing objectives for the integrated Unicracking/Unionfining unit are:
• Maximise VGO conversion
• Produce and maximise total diesel – 1D diesel fuel oil and regional diesel grades – while meeting diesel specifications such as flash point, cetane number and cloud point specifications
• Achieve minimum 24 months and preferred 36 months catalyst cycle length
• Maximise ebullated bed hydrocracker VGO end point while maintaining stable catalyst operation.
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