Hydrotreating Processes – Current Status and Future Challenges for a Fundamental Technology to the Downstream Industry

Introduction and Context

       Over the years, in face of the rising pollution levels associated with the technological development and the rise in petroleum consumption, the environment legislation has become increasingly severe.

           Restrictions on SOx and NOx emissions induced the necessity to higher technology development that can allow reducing the contaminants levels in the petroleum derivates, mainly sulfur and nitrogen. Normally, the concentration of contaminants increases with the density of the petroleum derivate. 

           A lot of technologies were applied to reduce the contaminants levels in the petroleum derivates, for example, the kerosene treating with Clay, the adsorption of sulfur compounds over black carbon and the recognized treatments Bender and Merox. The mentioned technologies show limitations, mainly when the concentration of contaminants is high.

       The hydrotreating technology (treatment with hydrogen) was studied by many researchers in the refining industry and academic sector over the decades and, currently, is practically impossible to attend the petroleum derivates specifications without these streams passing through the hydrotreating unit. For this reason, the hydrotreating technologies became essential to the players of the modern downstream industry. The dependence of the downstream industry from hydroprocessing technologies became even more important after the start of IMO 2020 which requires a deepest capacity to add value to the bottom barrel streams, especially for those refiners processing heavy and extra-heavy crudes.

           Due to these characteristics, the hydrotreating or hydroprocessing technologies became fundamental to sustain the current and future status of the downstream industry and the necessity to achieve increasingly low contaminants crude oil derivatives lead some challenges to refiners and technology developers, especially related to find cleaner sources of hydrogen.

Hydrotreating Technologies – An Overview

           The hydrotreating process involves a series of chemical reactions between hydrogen and organic compounds containing the contaminants (N, S, O, etc.). According to the target contaminant of the hydrotreating, the process can be called hydrodesulfurization (removing S), hydrodenitrogenation (removing N), hydrodeoxygenation (removing O) or hydrodearomatization when the main objective is to saturate of aromatic compounds, among others.

The most commons hydrotreating forms are hydrodesulfurization (where the objective is to remove compounds like benzothiophene, dibenzothiophene, etc.) and the hydrodenitrogenation (removing porphyrins, quinolines, etc.) These compounds, besides provoke emissions of SOx and NOx when are burned, produce in the derivates acidity, color and chemical instability.

The main chemical reactions associated with the hydrotreating process can be represented like below:

R-CH=CH2 + H2 → R-CH2-CH3 (Olefins Saturation)

R-SH + H2 → R-H + H2S (Hydrodesulfurization)

R-NH2 + H2 → R-H + NH3 (Hydrodenitrogenation)

R-OH + H2 → R-H + H2O (Hydrodeoxigenation)

Where R represents a hydrocarbon.

           The hydrotreating reactions are exothermic, and reactor temperature is controlled through injection of cold hydrogen between the catalyst beds.

           The hydrotreating process is normally conducted in fixed bed reactors and the most applied catalysts are Cobalt (Co), Nickel (Ni), Molybdenum (Mo) and Tungsten (W), commonly in association with then and supported in alumina (Al2O3). The association Co/Mo is applied in reactions that need lower reactional severity like hydrodesulfurization, while the catalyst Ni/Mo is normally applied in reactions that need higher severity, like hydrodenitrogenation and aromatics saturation. Due to the higher activity, the required catalyst volume is lower when Ni/Mo is applied.

           The hydrotreating is applied in the finishing of the final products like gasoline, diesel or kerosene or like intermediate step in the refining scheme in refineries to prepare feed charges to other processes like Residues Fluid Catalytic Cracking (RFCC) or Hydrocracking (HCC) where the main objective is to protect the catalyst applied in these processes.

           The basic process flow is similar to the various hydrotreating processes (hydrodesulfurization, hydrodenitrogenation, etc.), however, the process severity, determined by variables like hydrogen partial pressure, temperature and catalyst vary and the contaminants removal is affected.

The hydrotreatment process units are optimized aiming a equilibrium between cited operational variables, because chemical reactions are exothermic and the decontrolled raising in the temperature can affect negatively the reactional equilibrium besides it’s possible the sintering of the catalysts, to minimize this risk normally the hydrotreating reactors have points between the catalyst beds where are injected hydrogen in lower temperature (quench lines) to permit a better control of the reactor temperature.

 Figure 1 shows a typical arrangement for a hydrotreating process unit with a single separating vessel. 

Figure 1 – Basic Process Flow Diagram for Low Severity Hydrotreating Process Units 

The configuration with a single separating vessel is normally applied in lower severity units, like hydrodesulfurization units. This arrangement is possible in this case because under reduced pressures the difference between water and hydrocarbons properties is large and the separation process needs reducing contact areas, so a single vessel can realize the separation process. 

           According to the feed stream, the hydrotreating units present some variations in his design and operation modes. Below, we describe some of the most severe hydrotreating units founded in the refining hardware.

Diesel Hydrotreating Units

           To comply with the new regulations, the Diesel production requires higher severity units. Normally the straight run Diesel is processing with unstable streams (Light Cycle Oil, Coke Gas Oil, etc.) in high severity units as presented in Figure 2, where is possible to remove nitrogen or aromatics saturation, the unit operates with two separating vessels.

The high severity is required once, in the special case of middle distillates like Diesel, the presence of contaminants like sulfide, tiophenes, and aromatics sulfur compounds like dibenzothiophenes is among the most difficult compounds to remove through hydrotreating. The hydrodesulfurization reactions are favored by higher temperatures, while the hydrodearomatization reactions are favored by higher hydrogen partial pressures, by this reason the performance of diesel hydrotreating units requires a good balance between these variables, especially to units processing streams from Fluid Catalytic Cracking units (FCC), like light cycle oil (LCO) that presents high aromaticity and high sulfur content.

For higher severity units like Diesel hydrotreating, the difference between water and hydrocarbons properties is small and the phase separation process needs higher interface area so, two separating vessels are applied, one under high pressure where the separation among liquid and gaseous phase (H2, H2S, NH3 and light hydrocarbons) occurs and other under low pressure where the separation between aqueous and hydrocarbon phase is promoted, apart from the separation of the remaining gases. Units with high severity operate under temperatures 330 to 380 oC and pressures varying from 40 to 120 bar. 

Figure 2 – Basic Process Flow Diagram for High Severity Hydrotreating Process Units 

Due to the stricter limit of sulfur content in the diesel (< 10 ppm), Ni/Mo is applied as catalyst to diesel hydrotreating units once this catalyst present higher activity to desulfurization reactions.

The principal process variables considered in diesel hydrotreating units is the total pressure, hydrogen partial pressure, make-up hydrogen purity, recycle gas rate, reactor temperature, and space velocity (liquid hourly velocity, LHSV). The space velocity defines the time required to achieve a desired performance of the reactions, this parameter can be defined as presented in equation 1.

LHSV (h-1) = Feed Rate (m3/h)/Catalyst Volume (m3)    (1)

The LHSV is a key parameter to hydrotreating units, not only to the design but also to the optimization of the unit once it’s possible to estimate the Start of Run (SOR) temperature and control the catalyst lifecycle based on the End of Run (EOR) temperature that is normally limited by the mechanical resistance of the material applied to reactors design. Typical diesel hydrotreating units present LSHV between 0,75 to 2,5 h-1. In some designs, especially for deep hydrodesulfurization units, the reaction section is separated in two stages with the removal of H2S and NH3 between the reaction stages aiming to minimize the deactivation effect of these gases over the catalyst, this can be especially attractive to hydrotreating units focused to produce ultra-low sulfur diesel (ULSD).

As aforementioned, Diesel is the crude oil derivative that had the most increasing demand in the last decades. This derivative is mainly applied as a transportation fuel by vehicles equipped with Diesel Cycle engines, is composed by hydrocarbons between C10 and C25 with a boiling range of 150 oC to 380 oC. The diesel ignition quality is measured through the Cetane Number that corresponds to a volumetric percentage of cetane (n-hexadecane) in a mixture with heptamethylnonane, burns with the same ignition quality of the analyzed diesel. The linear paraffinic hydrocarbons are the compounds that most contributes to the diesel ignition quality, raising the cetane number while the presence of aromatics reduce this parameter and prejudice the ignition quality, currently, the minimum cetane number of commercial diesel is 48.

Another important parameter controlled in the diesel is the plugging point that aims to control the content of linear paraffins that tends to crystallize under low temperatures prejudice the fuel supply to the engine. The plugging point is determined according to the weather conditions in the region of application, in Brazil the plugging point is controlled in the range of 0 to 10 oC, in colder regions the cold flow properties tends to be a significant concern to refiners, especially those processing light and paraffinic crudes like north American shale oils, in these cases the refiners normally install dewaxing beds in the hydrotreating reactors containing catalysts based on zeolites to promote the cracking of longer paraffin.

The Diesel emissions control is carried out managing the fuel density aiming to control the content of heavy compounds, especially polyaromatics. Currently, the density of commercial diesel is controlled in the range of 830 to 865 kg/m3, to ultra-low sulfur diesel (ULSD), this parameter is controlled below 850 kg/m3. In the last decades had been great efforts to reduce the environmental damage produced by the diesel burn, nowadays, the environmental regulations require the commercialization of low sulfur diesel with a maximum sulfur content of 10 ppm, despite in some markets mainly in developing countries still are commercialized diesel with higher sulfur content (500 ppm), but this tends to change in the near future.

Great efforts was employed in the hydrotreating technology development, however, technology licensors like Axens, UOP, Exxon Mobil, Lummus, Haldor Topsoe, Albemarle among others, still invest in researches to improve the technology, mainly in the development of new arrangements that can minimize the hydrogen consumption (high cost raw material) and that apply lower cost catalysts and more resistant to deactivation process.

Bottom Barrel Hydrotreating Technologies

The hydroprocessing of residual streams presents additional challenges when compared with the treating of lighter streams, mainly due to the higher contaminants content and residual carbon (RCR) related with the high concentration of resins and asphaltenes in the bottom barrel streams. Higher metals and asphaltenes content lead to a quick deactivation of the catalysts through high coke deposition rate, catalytic matrix degradation by metals like nickel and vanadium or even by the plugging of catalyst pores produced by the adsorption of metals and high molecular weight molecules in the catalyst surface. By this reason, according to the content of asphaltenes and metals in the feed stream are adopted more versatile technologies aiming to ensure an adequate operational campaign and an effective treatment.

In order to carry out the hydroprocessing reactions, it’s necessary the mass transfer of reactants to the catalyst pores, adsorption on the active sites to posterior chemical reactions and desorption. In the case of bottom barrel streams processing, the high molecular weight and high contaminants content require a higher catalyst porosity aiming to allow the access of these reactants to the active sites allowing the reactions of hydrodemetallization, hydrodesulfurization, hydrodenitrogenation, etc. Furthermore, part of the feed stream can be in the liquid phase, creating additional difficulties to the mass transfer due to the lower diffusivity. To minimize the plugging effect, in fixed bed reactors, the first beds are filled with higher porosity solids without catalytic activity and act as filters to the solids present in the feed stream protecting the most active catalyst from the deactivation (guard beds).

The process conditions are severer in the residue hydrotreating. The feed stream characteristics lead to a strong tendency of coke deposition on the catalyst requiring higher hydrogen partial pressures (until 160 bar to fixed bed reactors) and higher temperatures (400 – 420 oC).

Bottom barrel streams hydroprocessing can be applied aiming to prepare the feed stream for another deep conversion processes like FCC and RFCC, it’s also common apply high severity hydrotreating process units to reduce the contaminants content to the processing in hydrocracking units, with the objective to protect the hydrocracking catalyst. The gas oil hydrotreating is very common in the preparation of feed stream to fluid catalytic cracking units (FCC) aiming to control the content f sulfur, metals and nitrogen as well as promote the opening of aromatics rings that are refractory of the catalytic cracking reactions.

Among the bottom barrel streams hydrotreating technologies we can quote the process Aroshift? developed by Haldor Topsoe Company, the Unionfining? process developed by UOP Company, the Hyvahl? technology by Axens Company and the RHU? process by Shell Company.

Due to the severe operational conditions, the operational costs tends to be higher to the bottom barrel hydroprocessing units when compared with units dedicated to treat distillate streams (Diesel, Kerosene, and Nafta). The most intense hydrogenation process lead to most robust catalytic bed cooling systems (quench), higher hydrogen replacing rates and complexes phase separation systems (multiple stages).

Despite the operational costs, the hydroprocessing of bottom barrel streams can ensure higher reliability and profitability to refiners through the reduction in the global operational costs related with shorter operational campaigns due to early catalyst deactivation as aforementioned. 

Beyond this, the relevance of residue hydroprocessing technologies tends to grow even more after 2020 when will start the new regulation on Bunker (Marine Fuel Oil), the IMO 2020. This important regulation will require the reduction in the sulfur content in this derivative from 3,5% (m.m) to 0,5% (m.m), this requirement should restrict the use of high contaminants content streams as diluents to the production of fuel oils like adopted nowadays, this fact would lead to applying high added value streams (diesel, as example) as diluent which can pressure the refiners profitability, in this scenario refineries with higher complexity should have competitive advantage over the competitors. From the Environmental point of view, the higher capacity of bottom barrel streams conversion minimizes the environmental footprint of the crude oil processing chain, ensuring the compliance with market demand and environmental requirements helping the downstream industry to meet the expectations of the society. 

Processing Extra Heavy Crudes – The Hydrocracking Solution

Refiners processing heavy and extra-heavy (or high sulfur) crudes face a great challenge to meet the IMO 2020 once is extremely difficult to comply with the new regulation through carbon rejection technologies, in this case, the hydrogen addition technologies are fundamental. The Table 1 presents the main differences between hydrotreating and hydrocracking technologies.

The hydrocracking process is normally conducted under severe reaction conditions with temperatures that vary to 300 to 480 oC and pressures between 35 to 260 bar. Due to process severity, hydrocracking units can process a large variety of feed streams, which can vary from gas oils to residues that can be converted into light and medium derivates, with high value added.

As aforementioned, the hydroprocessing of residual streams presents additional challenges when compared with the treating of lighter streams, mainly due to the higher contaminants content and residual carbon (RCR) related with the high concentration of resins and asphaltenes in the bottom barrel streams. Figure 3 shows a schematic diagram of the residue upgrading technologies applied according to the metals and asphaltenes content in the feed stream. 

Figure 3 – Residue Upgrading Technologies According to the Contaminants Content (Encyclopedia of Hydrocarbons, 2006)

Higher metals and asphaltenes content lead to a quick deactivation of the catalysts through high coke deposition rate, catalytic matrix degradation by metals like nickel and vanadium or even by the plugging of catalyst pores produced by the adsorption of metals and high molecular weight molecules in the catalyst surface. By this reason, according to the content of asphaltenes and metals in the feed stream are adopted more versatile technologies aiming to ensure an adequate operational campaign and an effective treatment.

As exposed above, extra-heavy crude oils or with high contaminants content can demand deep conversion technologies to meet the new quality requirements to the bunker fuel oil. Hydrocracking technologies are capable to achieve conversions higher than 90% and, despite, the high operational costs and installation can be attractive alternatives.

The hydrocracking process is normally conducted under severe reaction conditions with temperatures that vary to 300 to 480 oC and pressures between 35 to 260 bar. Due to process severity, hydrocracking units can process a large variety of feed streams, which can vary from gas oils to residues that can be converted into light and medium derivates, with high value added.

 Figure 4 shows a typical process arrangement to hydrocracking units with two reaction stage and intermediate gas separation, adequate to treat high streams with high contaminants content. 

Figure 4 – Typical Arrangement for Two Stage Hydrocracking Units with Intermediate Gas Separation

The residue produced by hydrocracking units have low contaminants content, able to be directed to the refinery fuel oil pool aiming to produce low sulfur bunker, allowing the market supply and the competitiveness of the refiners.

The process shown in Figure 4 presents a fixed bed hydrocracking unit, to heavier crudes, this unit can be inadequate due to the low operating life cycle, in this case the ebulated bed and slurry phase reactors can be more effective, despite the higher capital spending. The capital requirement is one of the most restriction to refiners in adopt the hydrocracking technologies both to capital and operating capital due to the necessity of larger hydrogen generation units, catalysts costs, etc. Figure 5 presents a comparison between residue upgrading alternatives related to the capital investment (CAPEX) and effectiveness in the bottom barrel processing.

Figure 5 – Capital Spending x Residue Conversion to Residue Upgrading Technologies (Shell Catalysts and Technologies, 2019)

As presented in Figure 5, the hydrocracking technologies present the higher level of required capital spending, on the other side offer the higher conversion to bottom barrel streams, a necessity to refiners processing heavy and extra-heavy crudes. According to Figure 3, the other alternatives are not effective to treating residue streams with high carbon residue and metals, common characteristics of extra-heavy crude oils. In this case, the hydrocracking alternative is the most technically adequate solution.

Hydrocracking Process – Some Commercial Technologies

Despite the high performance, the fixed bed hydrocracking technologies can be not economically effective to treat residue from heavy and extra-heavy due to the short operating lifecycle. Technologies that use ebullated bed reactors and continuum catalyst replacement allow higher campaign period and higher conversion rates, among these technologies the most known are the H-Oil and Hyvahl? technologies developed by Axens Company, the LC-Fining Process by Chevron-Lummus, and the Hycon? process by Shell Global Solutions. These reactors operate at temperatures above of 450 oC and pressures until 250 bar. Figure 6 presents a typical process flow diagram for a LC-Fining? process unit, developed by Chevron Lummus Company while the H-Oil? process by Axens Company is presented in Figure 7.

Figure 6 – Process Flow Diagram for LC-Fining? Technology by CLG Company (MUKHERJEE & GILLIS, 2018)

Catalysts applied in hydrocracking processes can be amorphous (alumina and silica-alumina) and crystalline (zeolites) and have bifunctional characteristics, once the cracking reactions (in the acid sites) and hydrogenation (in the metals sites) occurs simultaneously. 

Figure 7 – Process Flow Diagram for H-Oil? Process by Axens Company (FRECON et. al, 2019)

An improvement in relation of ebullated bed technologies is the slurry phase reactors, which can achieve conversions higher than 95 %. In this case, the main available technologies are the HDH? process (Hydrocracking-Distillation-Hydrotreatment), developed by PDVSA-Intevep, VEBA-Combicracking Process (VCC)? commercialized by KBR Company, the EST? process (Eni Slurry Technology) developed by Italian state oil company ENI, and the Uniflex? technology developed by UOP Company. Figure 8 presents a basic process flow diagram for the VCC? technology by KBR Company.

Figure 8 – Basic Process Arrangement for VCC? Slurry Hydrocracking by KBR Company (KBR Company, 2019)

In the slurry phase hydrocracking units, the catalysts in injected with the feedstock and activated in situ while the reactions are carried out in slurry phase reactors, minimizing the reactivation issue and ensuring higher conversions and operating lifecycle. Figure 9 presents a basic process flow diagram for the Uniflex? slurry hydrocracking technology by UOP Company.

Figure 9 – Process Flow Diagram for Uniflex? Slurry Phase Hydrocracking Technology by UOP Company (UOP Company, 2019).

As aforementioned, another commercial slurry phase hydrocracking process is the EST? technology by ENI Company, this process is shown in Figure 10.

Figure 10 – Basic Scheme for EST? Hydrocracking Technology by ENI Company (ENI Company, 2019).

Other commercial technologies to slurry hydrocracking process are the LC-Slurry? technology developed by Chevron Lummus Company and the Microcat-RC? process by Exxon Mobil Company. Aiming to meet the new bunker quality requirements, noblest streams, normally directed to produce middle distillates can be applied to produce low sulfur fuel oil, this can lead to a shortage of intermediate streams to produce these derivatives, raising his prices. The market of high sulfur content fuel oil should strongly be reduced, due to the higher prices gap when compared with diesel, his production tends to be economically unattractive.

Challenges to the Hydroprocessing Technologies – Renewables processing and Green Hydrogen Sources

           Despite the advantages of environmental footprint reduction of the refining industry operations, renewables processing presents some technological challenges to refiners. Figure 11 presents the chemical mechanism for the processing of vegetable/animal oils in hydrotreating units. 

Figure 11 – Chemical Mechanism of the Renewable Feedstream Hydrotreating (Article by ExxonMobil Company, 2011)

The renewable streams have a great number of unsaturations and oxygen in his molecules which lead to high heat release rates and high hydrogen consumption, this fact leads to the necessity of higher capacity of heat removal from hydrotreating reactors aiming to avoid damage to the catalysts. The main chemical reactions associated with the renewable streams hydrotreating process can be represented as below:

R-CH=CH2 + H2 → R-CH2-CH3 (Olefins Saturation)

R-OH + H2 → R-H + H2O (Hydrodeoxigenation)

Where R represents a hydrocarbon.

These characteristics lead to the necessity of higher hydrogen production capacity by the refiners as well as quenching systems of hydrotreating reactors more robust or, in some cases, the reduction of processing capacity to absorb the renewable streams. In this point it’s important to consider a viability analysis related to the use of renewables in the crude oil refineries once the higher necessity of hydrogen generation implies in higher CO2 emissions through the natural gas reforming process that is the most applied process to produce hydrogen in commercial scale.  

CH4 + H2O = CO + 3H2    (Steam Reforming Reaction - Endothermic)

CO + H2O = CO2 + H2      (Shift Reaction - Exothermic)

This fact leads some technology licensors to dedicate his efforts to look for alternative routes for hydrogen production in large scale in a more sustainable manner. Some alternatives pointed can offer promising advantages:

·      Natural Gas Steam Reforming with Carbon Capture – The carbon capture technology and cost can be limiting factor among refiners;

·      Natural Gas Steam Reforming applying biogas – The main difficult in this alternative is a reliable source of biogas as well as their cost.;

·      Reverse water gas shift reaction (CO2 = H2 + CO) – One of the most attractive technology, mainly to produce renewable syngas;

·      Electrolysis – The technology is one of the more promising to the near future.

Figure 12 presents a processing scheme to produce hydrocarbons applying renewable hydrogen, based in the Roland Berger Company concept.

Figure 12 – Hydrocarbons Production Routes Applying Renewable Hydrogen (Roland Berger Company, 2020).

As aforementioned, hydrogen is a key enabler to the future of the downstream industry and the development of renewable sources of hydrogen is fundamental to the success of the efforts to the energy transition to a lower carbon profile.

           Another challenge associated with renewables processing is the cold start characteristics of the derivatives, mainly Diesel and Jet Fuel. The renewable feed streams produce highly paraffinic derivatives after hydrotreating step as described in Figure 11, in this sense, the final derivative tends to show a higher cloud point which can be a severe restriction in colder markets as the northern hemisphere.  

           In these markets, refiners tend to apply catalytic beds containing dewaxing catalysts (ZSM-5) in his hydrotreating units or cloud point depressors additives which can raise the operation costs. Another side effect of renewables processing in conventional hydrotreating units is related to the heat release due to the high concentration of molecules insaturations and oxygen, at his point it’s important to remember that the conventional hydrotreating units was designed to treat low concentration contaminants, this fact can lead to high temperature in the catalyst bed leading to activity losses. As aforementioned, the high hydrogen consumption can be a severe bottleneck to some refiners, leading these players to operate these units under low processing flowrate.

           The renewables processing tends to be a constant in the downstream industry for the next years, leading to the technology developers to focus his efforts to the design of specific catalysts and reactors (quenching systems) to deal with growing participation o renewable raw material in the hydroprocessing feeds.

Conclusion

           The hydroprocessing technologies became fundamental to the crude oil refining industry in the last years, once is practically impossible to produce marketable crude oil derivatives without at least one hydroprocessing step. The diesel and naphtha hydrotreating units are especially relevant to refiners inserted in high demand by transportation fuels like Brazil, in these markets, the hydroprocessing capacity in a key factor to ensure economic operations and competitiveness to refiners as well as compliance with market demand and environmental regulations. Regarding the bottom barrel hydrotreating units, the IMO 2020 raised, even more, the relevance of these units to the competitiveness of the refiners.

Once the low sulfur crude oils are scarce, the refiners need to look for alternative routes to add value to his crude oil reserves as well as to supply the new marine fuel oil, ensuring participation in a profitable market.

The challenges imposed by the current scenario to the hydroprocessing units are related to the search for cleaner sources of hydrogen as well as the growing participation of renewable raw material in the feedstock, leading to the necessity to specific design of reactors and catalysts.

The capacity to add value to the bottom barrel streams is a competitive differential in the refining industry and this differential tends to be even more relevant in the market scenario with the IMO 2020, especially in markets with easy access to high sulfur crude oils. Under this condition, the presence of deep hydroprocessing units in the refining scheme can ensure a considerable competitive advantage to refiners, even considering the high capital spending. As aforementioned, the hydrotreating units are strategic to refiners and ensure an adequate operating lifecycle and reliable operations to these units is a key issue to ensure profitable and competitive operations in the modern downstream industry.

 References:

CACKETT, S. – IMO 2020 and Bottom of the Barrel Opportunities (Shell Catalysts and Technologies). Presented at 2nd Residue Hydrotreat, Kuwait, 2019.

Encyclopedia of Hydrocarbons (ENI), Volume II – Refining and Petrochemicals (2006).

FRECON, J.; LE BARS, D.; RAULT, J. – Flexible Upgrading of Heavy Feedstocks. PTQ Magazine, 2019.

GARY, J. H.; HANDWERK, G. E. Petroleum Refining – Technology and Economics.4th ed. Marcel Dekker., 2001.

HILBERT, T.; KALYANARAMAN, M.; NOVAK, B.; GATT, J.; GOODING, B.; McCARTHY, S. - Maximising Premium Distillate by Catalytic Dewaxing, 2011.

MUKHERJEE, U.; GILLIS, D. – Advances in Residue Hydrocracking. PTQ Magazine, 2018.

ROBINSON, P.R.; HSU, C.S. Handbook of Petroleum Technology. 1st ed. Springer, 2017.

ZHU, F.; HOEHN, R.; THAKKAR, V.; YUH, E. Hydroprocessing for Clean Energy – Design, Operation, and Optimization. 1st ed. Wiley Press, 2017.

Dr. Marcio Wagner da Silva is Process Engineer and Project Manager focusing on Crude Oil Refining Industry based in S?o José dos Campos, Brazil. Bachelor in Chemical Engineering from University of Maringa (UEM), Brazil and PhD. in Chemical Engineering from University of Campinas (UNICAMP), Brazil. Has extensive experience in research, design and construction to oil and gas industry including developing and coordinating projects to operational improvements and debottlenecking to bottom barrel units, moreover Dr. Marcio Wagner have MBA in Project Management from Federal University of Rio de Janeiro (UFRJ) and is certified in Business from Getulio Vargas Foundation (FGV).