In this study, we investigate the feasibility of co-processing biocrude in petroleum vacuum gas oil (VGO) hydroprocessing units. The biogenic component of the feed was biocrude produced by hydrothermal liquefaction of woody biomass, while VGO from oil sand bitumen was selected as the hydrocarbon feed. To improve its processability, the biocrude sample was distilled to remove high boiling components prior to testing. Systematic experiments were conducted in a continuous hydroprocessing pilot unit at co-processing ratios of up to 15 vol % biocrude and reaction temperatures of 350–380 °C, including baseline tests with pure VGO, to understand process impacts. The operating range where there was a minimal effect on hydrodesulfurization and hydrodenitrogenation activity levels over the baseline was at co-processing ratios below 10 vol % biocrude and temperatures of 370 °C and above. Monitoring of catalyst stability through check-back experiments with pure VGO revealed visible deactivation trends at co-processing ratios above 10 vol % biocrude. Radiocarbon analysis allowed the establishment of the fate of biogenic carbon added to the co-processing feed. This study suggests that VGO hydroprocessing units, as normally used at the front of fluid catalytic cracking and hydrocracking units in a refinery, could be a suitable cut-in point for biocrude within a carefully delimited operating window.

In this study, we investigate the potential of co-processing hydrothermal liquefaction (HTL) biocrude with vacuum gas oil (VGO) in a hydrocracking process with hydrotreating as the first step. Experiments were conducted in a continuous hydroprocessing pilot plant in two stages: hydrotreating and hydrocracking. Two feeds were tested: first pure VGO to establish a baseline and then a co-processing blend having 7.5 vol % HTL biocrude. In the first stage, the VGO and co-processing blend were sequentially hydrotreated to meet the quality specification of the hydrocracking catalyst. The second stage consisted of hydrocracking the two hydrotreated products from the first stage, and the resulting products were distilled into naphtha, diesel, and jet fuel fractions for characterization. The hydrotreating step achieved satisfactory sulfur and nitrogen removal levels for both feeds, but it was ineffective in converting oxygen compounds in the co-processing blend, resulting in a product with 1530 ppmw oxygen. During hydrocracking, the co-processing blend required a higher reaction temperature than the baseline VGO to achieve the same conversion level, a behavior attributed to the oxygen and nitrogen levels in the co-processing blend after hydrotreating. Despite these effects, overall product distribution and hydrogen consumption for both scenarios were quite comparable. Characterization of hydrocracked products showed only subtle differences in quality and hydrocarbon type composition, while biogenic carbon measurements revealed that the majority of biogenic carbon is transferred to the naphtha, diesel, and jet fuel fractions.

Instability associated with the presence of olefins in bitumen that is thermally processed during partial upgrading is a major concern for pipeline transportation and downstream refining. A common strategy for stabilizing thermally processed oils is to selectively hydrogenate the olefin-rich fractions, typically, the naphtha fraction (IBP−204 °C). In this paper, olefin hydrogenation was studied with hydrotreated bitumen-derived naphtha spiked with five model olefin compounds under mild hydrotreating conditions. The hydrogenation reactivities of the five model olefin/diolefin compounds are ranked in the order 1,3hexadiene > allylbenzene > 1-heptene > 2-methyl-2-pentene > 1-methyl-cyclopentene. The reactivity is largely determined by the position of the double bond, and, to a lesser extent, by the molecular structure of the olefin. The conjugated diolefin, 1,3hexadiene, was the most reactive. The two terminal olefins, 1-heptene and allylbenzene, were observed to be more reactive than the two olefins with internal double bonds: 2-methyl-2-pentene and 1-methyl-cyclopentene. Results also show that temperature has a significant effect on olefin hydrogenation performance, with the pressure and the liquid hourly space velocity having relatively moderate effects. Meanwhile, flash calculations confirmed the presence of vapor−liquid equilibrium under the operation conditions used. When the reactor temperature is 150 °C or less, reactions primarily occur in the liquid phase, whereas at temperatures of 200 °C or higher, the reactions occur in the vapor phase. A hydrogenation kinetics model is proposed that successfully describes the observed trends of olefin hydrogenation in the liquid phase.

A life cycle-based model, OSTUM (Oil Sands Technologies for Upgrading Model), which evaluates the energy intensity and greenhouse gas (GHG) emissions of current oil sands upgrading technologies, is developed. Upgrading converts oil sands bitumen into high quality synthetic crude oil (SCO), a refinery feedstock. OSTUM's novel attributes include the following: the breadth of technologies and upgrading operations options that can be analyzed, energy intensity and GHG emissions being estimated at the process unit level, it not being dependent on a proprietary process simulator, and use of publicly available data. OSTUM is applied to a hypothetical, but realistic, upgrading operation based on delayed coking, the most common upgrading technology, resulting in emissions of 328 kg COe/m SCO. The primary contributor to upgrading emissions (45%) is the use of natural gas for hydrogen production through steam methane reforming, followed by the use of natural gas as fuel in the rest of the process units' heaters (39%). OSTUM's results are in agreement with those of a process simulation model developed by CanmetENERGY, other literature, and confidential data of a commercial upgrading operation. For the application of the model, emissions are found to be most sensitive to the amount of natural gas utilized as feedstock by the steam methane reformer. OSTUM is capable of evaluating the impact of different technologies, feedstock qualities, operating conditions, and fuel mixes on upgrading emissions, and its life cycle perspective allows easy incorporation of results into well-to-wheel analyses.

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The stabilization of olefins in a thermally processed bitumen is a focal area for the development of bitumen partial upgrading technologies. Although a number of approaches have been proposed, including alkylation, oligomerization, and adsorption, hydrotreatment is still the most effective strategy for treating olefins in thermally cracked products such as coker naphtha. In our previous work, we studied the hydrogenation of model olefin compounds to understand their reactivity under mild conditions. This paper is a follow-up study focusing on the hydrotreatment of olefins in a thermally processed bitumen using a bench-scale continuous hydroprocessing unit. Two different scenarios were investigated: (1) hydrotreating the olefin-rich light fraction (IBP-280 °C) of the thermally processed bitumen product and (2) hydrotreating the whole product. The cracked feedstock was prepared by processing oil sand bitumen under visbreaking conditions. It was found that on-specification product for olefin content (<1.0 wt % 1-decene equivalent) could be obtained by hydrotreating the light fraction at lower temperatures (∼275–300 °C) and with less hydrogen as compared to hydrotreating the whole bitumen product, for which temperatures close to 325 °C are required in addition to about double the hydrogen input. Hydrotreating the whole product, however, brings the benefit of markedly reducing the total acid number and increasing the American Petroleum Institute gravity, which can be helpful to achieve the product quality goals of partial upgrading. Product characterization by advanced techniques such as 1H NMR and two-dimensional gas chromatography has revealed interesting reactivity patterns of olefins, sulfur compounds, and aromatics during mild hydrotreatment.

The co‐processing of biocrude in petroleum refineries is viewed as an economical and practical pathway to produce low‐carbon fuels. A major challenge to co‐processing is the poor miscibility of biocrudes with petroleum due to their high levels of oxygen. This study investigated the mild hydrodeoxygenation of biocrude derived from hydrothermal liquefaction (HTL) of agriculture waste as a means to enhance its miscibility with petroleum vacuum gas oil (VGO). Blending compatibility tests were performed to identify the extent of deoxygenation required to achieve blending of 10 wt% treated biocrude in VGO. The highest oxygen removal (~72%) was achieved by increasing the temperature in three steps (240, 280, and 300 °C), with pressure kept at 1400 psi and a catalyst‐to‐feed ratio of 0.19 g g−1. Under such conditions, the hydrotreated biocrude was found to be miscible in VGO and the resulting blend was stable over 7 days. The hydrotreated biocrude products were characterized using nuclear magnetic resonance to identify changes in oxygenated compound classes, such as carboxylic acids, alcohols, ethers, carbohydrates, carbonyls, and phenolics. Carboxylics and phenolics were identified as important contributors to the miscibility of the biocrude. In further testing, two 10 wt% blends of hydrotreated and raw biocrude in VGO were co‐processed through hydrotreating. These supplementary tests confirmed that the hydrotreated biocrude performed better in terms of catalytic activity than the raw biocrude. © 2021 Her Majesty the Queen in Right of Canada. Biofuels, Bioproducts and Biorefining © 2021 Society of Industrial Chemistry and John Wiley & Sons Ltd. Reproduced with the permission of the Minister of Natural Resources Canada.

To fully advance our understanding of hydrocarbon conversion chemistry requires powerful analytical methods to qualitatively and quantitatively characterize complex petroleum fractions at the molecular level. In the absence of such tools, an alternative solution is to model the molecular composition of hydrocarbon mixtures with limited analytical data. The objective of this study is to integrate modeling techniques with conventional and advanced petroleum characterization methods to derive the composition of middle distillate fractions at the molecular level. In the present approach, analytical petroleum characterization data are used as input to computationally generate a mixture of representative molecules that mimics the properties of the real sample. The representing molecules are constructed according to coherent chemical/thermodynamic criteria by Monte Carlo sampling of a set of statistical functions assigned to each possible molecular feature. The assembled mixture is built on a large set of chemical species and is further optimized with the principle of Maximum Entropy. The approach is applied to simulating two middle distillates differing significantly in hydrocarbon type composition and origin. The samples are experimentally characterized by standard and advanced analytical methods: density, simulated distillation, elemental analysis, hydrocarbon types/distributions and sulfur compound speciation by two-dimensional gas chromatography with flame ionization detector (GC × GC−FID) and sulfur chemiluminescence detector (GC × GC−SCD), and 13 C nuclear magnetic resonance (NMR), to obtain sufficient information for parameter fitting and model validation. Simulation results showed that the model is capable of generating representative mixtures that reasonably match the actual physical samples in analytical properties and carbon number distributions.