Hydrocracking Processing Units as Competitive Advantage among Refiners in a Changing Downstream Market

Introduction and Context

The necessity to reduce the environmental impact and the higher sustainability of the industrial processes normally is translated in stricter regulations and higher control upon the industries activities, mainly to those that have a high environmental footprint as the crude oil production chain. This fact is positive and welcome, in view of the necessity to preserve the natural resources and the needed technological development to meet these regulations.

One of the most impacting regulations to the downstream industry is the necessity to reduce the sulfur content in the maritime fuels, known as IMO 2020, this regulation established which from the maximum sulfur content in the maritime transport fuel oil (Bunker) is 0,5 % (m.m) against the previously 3,5 % (m.m). The main objective is to reduce the SOx emissions from maritime fleet, significantly decreasing the environmental impact of this business.

The marine fuel oil, known as bunker, is a relatively low viscosity fuel oil applied in diesel cycle engines to ships movement. Before 2020, the bunker was produced through the blending of residual streams as vacuum residue and deasphalted oil with dilutants like heavy gasoil and light cycle oil (LCO), due to the new regulation, a major part of the refiners will not be capable to produce low sulfur bunker through simple blend.

Due be produced from residual streams with high molecular weight, there is a tendency of contaminants accumulation (sulfur, nitrogen, and metals) in the bunker, this fact makes difficult meet the new regulation without additional treatment steps, what should lead to increasing the production cost of this derivative and the necessity to modifications in the refining schemes of some refineries. Figure 1 presents a schematic diagram of how the bunker was produced before the IMO 2020.

Figure 1 – Bunker Production Process before IMO 2020

The drastic reduction of sulfur content in the final product, lead refiners to look for alternatives to reduce the sulfur content in the intermediate streams, and this is a hard task to refiners processing heavy and extra-heavy crudes.

Beyond the necessity to add value to bottom barrel streams in compliance with the IMO 2020, the increasingly restrict environmental regulations requires even more capacity to produce cleaner distillates, imposing another challenge to refiners processing extra-heavy crudes. The growing trend of petrochemical integration is another great challenge to refiners with access to extra-heavy crudes once requires more complex and expensive refining hardware, in this sense, the hydrocracking and deep hydrocracking technologies can be a fundamental tool to allow the refiners with high capital investment capacity to reach a highlighted competitive positioning in the downstream market through adequate balance of bottom barrel conversion capacity and petrochemicals maximization.

The war between Russia and Ukraine raised the spread between the 0,5 % sulfur and 3,5 % sulfur marine fuel oil, as presented in Figure 2, becoming even more attractive the production of VLSFO.

Figure 2 – VLFSO and HSFO Fuel oil Spreads (Ship & Bunker, 2022)

Even before the war the spread between VLSFO and HSFO the justify the investments by refiners to produce the low sulfur fuel. Furthermore, it’s important to considering the increasingly stricter regulations and the trend of reduction of the HSFO market in the middle term (as presented in Figure 3), this fact plus the trend of reduction in transportation fuels demand and growing demand of petrochemicals at global level tends to favor refiners relying on most complex refining hardware that are capable to processing heavy crude oils and maximize the added value to the processed crude.

Figure 3 – Growing Participation of VLFSO in the Bunker Market (IEA, 2021)

Flexible refining hardware in relation of the processed crude slate is an important competitive advantage in the downstream sector, mainly the processing of heavy and extra-heavy crudes due to his lower acquisition cost when compared with the lighter crude oils.  The difference in the acquisition cost between these oils is based on in the yield of high added value streams which these oils present in the distillation process, once the lighter crudes normally show higher yields of distillates than the heavier crudes, his market value tends to be higher. As an example, Figure 4 presents the evolution of the discount of WCS (West Canadian Select) crude oil to WTI (West Texas Intermediate) crude oil over the time.

Figure 4 – Price gap between WTI and WCS crude oils (CBC News, 2022)

The WCS is considered a heavy crude (API grade between 19 and 22) with a sulfur content around 3,0 % while the WTI is considered a reference crude with a medium API grade around 40 with very low sulfur content (around 0,3 %), Figure 1 shows a significant price gap between these crudes, leading to a relatively advantage to refiners capable to add value to these crudes, especially considering the IMO 2020 that requires even more refining capacity to add value to the bottom barrel streams. Normally, the valuation of crudes is defined by the quality, the available market in other words it’s necessary to find refiners capable to process this crude oil, and the capacity to transport the crude oil to the consumer market. Heavier crudes tend to present discounts related to lighter crudes due to these three variables:

·       Quality – Heavier crudes presents lower yield of distillates and high added value derivatives like diesel, kerosene, and gasoline than lighter crudes;

·       Consumer market – The refiners able to process heavier crudes needs to rely on adequate bottom barrel conversion capacity, in other words, more complex refineries, restricting the consumer market in comparison with lighter crudes;

·       Transportation – Heavier crudes presents higher logistics costs due to higher energy consumption;

Despite these characteristics, refiners with adequate refining hardware and easy access to heavier crudes can use the price gap between light and heavy crudes as opportunity to improve the refining margins, mainly considering the IMO 2020 that reduced, even more, the acquisition cost of heavier and sourer crudes and due to their characteristics, the hydrocracking technologies broke significative restrictions of the refining hardware to add value to these discounted crudes.

Processing Extra Heavy Crudes – The Hydrocracking Alternative

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 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 5 shows a schematic diagram of the residue upgrading technologies applied according to the metals and asphaltenes content in the feed stream.

Figure 5 – Residue Upgrading Technologies According to the Contaminants Content (Encyclopedia of Hydrocarbons, 2006)

Higher metals and asphaltenes content led 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.

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. The active metals used to this process are normally Ni, Co, Mo and W in combination with noble metals like Pt and Pd.

It’s necessary a synergic effect between the catalyst and the hydrogen because the cracking reactions are endothermic and the hydrogenation reactions are exothermic, so the reaction is conducted under high partial hydrogen pressures and the temperature is controlled in the minimum necessary to convert the feed stream. Despite these characteristics, the hydrocracking global process is highly exothermic, and the reaction temperature control is normally made through cold hydrogen injection between the catalytic beds.

According to the feed stream quality (contaminants content), its necessary hydrotreating reactors installation upstream of the hydrocracking reactors, these reactors act like guard bed to protect the hydrocracking catalyst.

The principal contaminant of hydrocracking catalyst is nitrogen, which can be present in two forms: Ammonia and organic nitrogen.

Ammonia (NH3), produced during the hydrotreating step, have temporary effect reducing the activity of the acid sites, mainly damaging the cracking reactions. In some cases, the increase of ammonia concentration in the catalytic bed is used like an operational variable to control the hydrocracking catalyst activity. The organic nitrogen has permanent effect blocking the catalytic sites and leading to coke deposits on the catalyst.

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 6 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 like nitrogen.

Figure 6 – 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 6 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 important restrictions to refiners to adopt the hydrocracking technologies both to capital and operating capital due to the necessity of larger hydrogen generation units, catalysts costs, etc. Figure 7 presents a comparison between residue upgrading alternatives related to the capital investment (CAPEX) and effectiveness in the bottom barrel processing.

Figure 7 – Capital Spending x Residue Conversion to Residue Upgrading Technologies (Shell Catalysts and Technologies, 2019)

As presented in Figure 7, 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.

According to data from Global Data Company, the global installed hydrocracking capacity in 2022 was around 12,500 Mbd and will growth under an average annual growth rate of 5,0 % until 2027 and this growth will be headed by USA, China, India, and Saudi Arabia.

Deep Hydrocracking Technologies – Recovering More Added Value from the Crudes

As aforementioned, 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 8 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 9.

Figure 8 – 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 9 – 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 10 presents a basic process flow diagram for the VCC™ technology by KBR Company.

Figure 10 – 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 11 presents a basic process flow diagram for the Uniflex™ slurry hydrocracking technology by UOP Company.

Figure 11 – Process Flow Diagram for Uniflex™ Slurry Phase Hydrocracking Technology by UOP Company (UOP 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. Figure 12 presents a basic process flow diagram for the LC-Slurry™ technology developed by Lummus Company.

Figure 12 – Basic Process Arrangement for LC-Slurry™ Technology developed by Lummus Company (BISWAS et. al., 2017)

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.

Deep Conversion Refining Hardware – Petrochemicals from Bottom Barrel Streams

As aforementioned the residue upgrading units are capable to improve the quality of bottom barrel streams, the main advantage of the integration between residue upgrading and petrochemical units like steam cracking is the higher availability of feeds with better crackability characteristics.

Bottom barrel streams tend to concentrate aromatics and polyaromatics compounds that present uneconomically performance in steam cracking units due the high yield of fuel oil that presents low added value, furthermore, the aromatics tends to suffer condensation reaction in the steam cracking furnaces, leading to high rates of coke deposition that reduces the operation lifecycle and raises the operating costs. In this case deep conversion units like hydrocracking can offer higher operational flexibility.

Once cracking potential is better to paraffinic molecules, and the hydrocracking technologies can improve the H/C in the molecules converting low added value bottom streams like vacuum gasoil to high quality naphtha, kerosene, and diesel the synergy between hydrocracking and steam cracking units, for example, can improve the yield of petrochemical intermediates in the refining hardware, an example of highly integrated refining configuration relying on hydrocracking is presented in Figure 13.

Figure 13 – Integrated Refining Scheme Relying on Residue Upgrading and Petrochemical Maximization Technologies (UOP, 2019)

Considering the recent trend of reduction in transportation fuels demand followed by the growth of petrochemicals market makes the presence of hydrocracking units in the refining hardware raise the availability of high-quality intermediate streams capable to be converted into petrochemicals, an attractive way to maximize the value addition to processed crude oil in the refining hardware. As presented in Figure 13, the synergy between carbon rejection and hydrogen addition technologies like FCC and hydrocracking units can offer an attractive alternative, sometimes the hydrocracking and FCC technologies are faced by competitors technologies in the refining hardware due to the similarities of feed streams that are processed in these units. In some refining schemes, the mild hydrocracking units can be applied as pretreatment step to FCC units, especially to bottom barrel streams with high metals content that are severe poison to FCC catalysts, furthermore the mild hydrocracking process can reduce the residual carbon to FCC feed, raising the performance of FCC unit and improving the yield of light products like naphtha, LPG, and olefins.

Considering the great flexibility of deep hydrocracking technologies that are capable to convert feed stream varying from gas oils to residue, an attractive alternative to improve the bottom barrel conversion capacity is to process in the hydrocracking units the uncracked residue in FCC unit aiming to improve the yield of high added value derivatives in the refining hardware, mainly middle distillates like diesel and kerosene.

As aforementioned, face the current trend of reduction in transportation fuels demand at the global level, the capacity of maximum adding value to crude oil can be a competitive differential to refiners. Due to the high capital investment needed for the implementation that allows the conventional refinery to achieve the maximization of chemicals, capital efficiency becomes also an extremely important factor in the current competitive scenario as well as the operational flexibility related to the processed crude oil slate.

Although the advantages presented by closer integration between refining and petrochemical assets, it’s important to understand that the players of downstream industry are facing with a transitive period where the transportation fuels are responsible by great part of the revenues. In this business scenario, it’s necessary to define a transition strategy where the economic sustainability achieved by the current status (transportation fuels) needs to be invested to build the future (maximize petrochemicals). Keep the eyes only in the future or only in the present can be a competitive mistake.

The Side Effect of Cracked Feeds – A Special Challenge to Hydrocracking Units

The most common cracked feeds directed to hydrocracking units are residual streams from FCC like Light Cycle (LCO) and Decanted Oil (DO) and Heavy Coker Gasoil (HCGO) from Delayed Coking units. Another less common feed is residue from Visbreaking units.

The main characteristics that influence in the hydrocracking performance for each feedstock is presented below:

·       FCC Cycle Oils – Present high aromaticity that are normally refractory to cracking reactions as well as refractory sulfur components, raising the sulfur content in the final products and reduction in diesel cetane number, on the other side, normally presents low basic nitrogen content that is a poison to the hydrocracking catalysts.

·       Thermal Cracking Feeds – Normally presents low aromatics content but concentrate refractory sulfur components.

The Heavy Coker Gasoil (HCGO) is an interesting case study as a feed to hycrocracking unit. Refiners with high complexity refining hardware can rely on the synergy between delayed coking and hydrocracking technologies to ensure added value to bottom barrel streams.

The quality of the HCGO relies on the quality of the feed to the delayed coking unit as well as the operating mode of the unit, mainly the recycle ratio. Higher recycle ratios produces better quality HCGO once reduces Conradson Carbon Residue (CCR), reducing the contaminants content like metals, sulfur, and nitrogen.

Despite this advantage, the delayed coking operators normally minimize the recycle ratio to minimum as possible aiming to raise the fresh feed processing capacity and the quality of HCGO is not an optimization focus of the refinery. For this reason, normally the HCGO is a hard feed to hydrocracking units due to the high content of refractory sulfur components, high CCR, high nitrogen content, and aromatics concentration.

The sulfur and nitrogen content raises the heat release in the first bed (Higher exothermal profile) that can produce damage to the catalysts, the nitrogen tends to inhibit the cracking reaction leading to lower conversion in the unit. Hydrocracker’s processing feeds with high nitrogen content tends to apply processing configuration with intermediate gas separation to control the catalyst activity. The higher production of H2S and NH3 due to the higher concentration of sulfur and nitrogen reduces the hydrogen partial pressure, raise the necessity of wash water to the units, and can raise the corrosion rate in the processing unit.

Aromatics compounds tend to raise the hydrogen consumption, the heat release in the catalyst bed, and are precursors of coking deposition that deactivate the catalyst. Other side effects of the cracked feeds to hydrocracking units are the impact over the quality of the final products like lower cetane number of diesel, higher smoke point of kerosene, lower viscosity index in the lubricating oils and higher sulfur content.

As described above, processing cracked feeds in hydrocracking units present some additional challenges to refiners related to hydrogen consumption, better quench design of the catalyst bed due to the higher exothermic profile of the reactions, and lower global activity of the catalyst due to the higher poison content, like basic nitrogen. These characteristics lead the refiners processing cracked feeds in hydrocracking units to invest more capital in feed treating systems like filtering and guard beds, despite this apparent disadvantage, refiners able to add value to bottom barrel streams can enjoy highly competitive advantage considering the downstream market post IMO 2020. For refiners processing extra-heavy bottom barrel streams, the deep hydrocracking technologies like slurry phase hydrocracking can be an interesting option, despite the high capital and operating costs.

The Lubricating Market – Short Lifetime to Solvent Route

According to data from Precedence Research Institute, is expected a growth of global market size from 145 US billion dollars in 2023 to 224,5 US billion dollars in 2034 under an compound annual growth (CAGR) of 4,0 % in the period as presented in Figure 16.

Figure 14 – Expected growth of the global market size between 2023 to 2034 (Precedence Research, 2024)

The high added value of lubricants in comparison with the transportation fuels accompanied by the trend of reduction in transportation fuels demand indicates an attractive alternative to refiners with adequate refining hardware to improve his revenues and the competitiveness in the downstream market.

Like others crude oil derivatives, the economic and technology development have been required the production of lubricating oils with higher quality and performance, moreover with lower contaminants content.

The main quality requirements for lubricating oils are viscosity, flash point, viscosity index (viscosity change with temperature), fluidity point, chemical stability, and volatility.

According to the American Petroleum Institute (API), the lubricating base oils can be classified as described in Table 1.

The lube oils from groups II, III and IV have higher quality than base oils from the group I, the content of contaminants like sulfur and unsaturated compounds are significantly reduced, moreover, the viscosity index are superior for groups II, III, and IV.

The main disadvantage of the solvent route, when compared with the hydrorefining route, is that the solvent route can produce only Group I lubricating oil, this can limit his application to restricted consumer markets, which can reflect in the economic viability. Figure 15 presents a forecast to the market share evolution to different kinds of base oils in the market.

Figure 15 – Base Oil Demand Distribution (STATISTA, 2020)

According to the data from Figure 15, is expected a significant reduction in the demand by Group I base oils, leading to a great competitive loss to refiners relying on base oil production exclusively through solvent routes.

Another solvent route disadvantage is the solvents applying which can cause environmental damage and needs specials security requirements during the processing, production of low value-added streams like aromatic extract is another disadvantage. In this sense, refiners relying on solvent routes tend to lose market in the next years and face difficulties to found markets for his products, reducing in a significant manner their competitiveness in the downstream market.

Producing High Quality Lubricating Oils – The Hydroprocessing Route

In the lubricating oil production by hydrorefining, the physical processes of the solvent route are substituted by catalytic processes, basically hydrotreating processes. Figure 16 shows a block diagram of the processing sequence to produce base lube oils through hydrorefining route.

Figure 16 - Processing Scheme for Base Lubricating Oil Production through Hydrorefining Route

In this case the fractionating in the vacuum distillation step has more flexibility than in the solvent route, once that the streams will be cracked in the hydrocracking unit, so another distillation step is necessary.

After the vacuum distillation and propane deasphalting steps, the process streams are sent to a hydrotreating unit, this step seeks to saturate polyaromatic compounds and remove contaminants like sulfur and mainly nitrogen which is a strong deactivation agent for the hydrocracking catalyst.

In the hydrocracking step, the feed stream is cracked under controlled conditions and chemical reactions like dehydrocyclization, and aromatics saturation occur which give to the process stream the adequate characteristics to the application as lubricants.              The following step, hydroisomerization, seeks to promote isomerization of linear paraffins (which can reduce de viscosity index) producing branched paraffins.

After the hydroisomerization the process stream is pumped to hydrofinishing units to saturate remaining polyaromatic compounds and to remove heteroatoms, in the hydrofininshing step the water content in the lube oil is controlled to avoid turbidity in the final product.

In hydrotreating units dedicated to produce lubricant, one of the focuses of the hydrotreating process is to reduce the concentration of long chain paraffin, to achieve this goal is applied a specific catalyst bed containing dewaxing catalysts (ZSM-5). One of the most known hydrodewaxing technology in the market is the MSDW™ process, commercialized by ExxonMobil Company. A basic process flow diagram for MSDW™ process is shown in Figure 17.

Figure 17 – Basic Process Flow Diagram for MSDW™ Dewaxing Technology by ExxonMobil Company (ExxonMobil Website).

HDF = Hydrofininshing

Another available hydrodewaxing technology is the Isodewaxing™ process, developed by Lummus Company, this process is shown in Figure 18.

Figure 18 – Basic Process Flow Diagram for the Isodewaxing™ technology by Lummus Company.

At this point is important to quote that the main quality requirements of the lubricating oils are put under control through the following processes:

·       Viscosity – The viscosity of the lubricating oil is controlled in the distillation step, managing the cuts in the crude distillation units or in the distillation columns after hydrocracking units;

·       Viscosity Index (VI) – This variable is controlled in the hydrocracking step through the reduction in the aromatics content;

·       Saturates – Another parameter that is adjusted in the hydrocracking step, through reduction of aromatics;

·       Pour Point – This quality requirement is controlled in the hydrodewaxing step, through the reduction of waxes content.

As an example, Figure 19 presents a refining configuration capable to produce high quality lubricating oils based on hydrorefining route.

Figure 19 – Lubricating Oil Production Based on Hydrorefining Route (Encyclopedia of Hydrocarbons, 2006)

Despite the high capital spending involved in the hydroprocessing route, it’s possible to achieve better quality, higher added value, and products with growing demand against the production of Group I lube that presents contraction demands. In this scenario, is expected which refiners relying on exclusively solvent routes, lose market share forcing revamps of the existing lubricating production units or the exit from the market.

As discussed above is expected a significant growth of the global hydrocracking installed capacity for the next years. As expected, this growth will be headed by the Asian refiners as presented in Figure 20.

Figure 20 – Participation in the Global Growth of Hydrocracking Capacity by Region (Global Data Company, 2023)

The headed by Asian players is expected once these players present high integration level between refining and petrochemical assets, requiring high bottom barrel conversion capacity to maximize the yield of petrochemicals, again this shows the competitive advantage for the Asian players due to the highest flexibility and profitability of their refining hardware.

Conclusion

Comply with IMO 2020 put under pressure the refining margins of low complexity refineries and reduced conversion capacity, once there is the tendency to raise the prices of low sulfur crude oils, furthermore, the higher operational costs depending on the technological or optimization solution adopted by the refiner. The challenge is even harder to refiners processing heavy and extra-heavy crudes, in this case, despite the high capital spending the hydrocracking technologies can offer an attractive alternative, beyond this, hydrocracking technologies appears like a fundamental enabler to ensure high conversion of bottom barrel streams, especially considering the growing trend of integration between refining and petrochemical assets. For refiners processing low sulfur crudes, the solvent deasphalting technologies can be an attractive way to comply with IMO 2020.

The downstream industry faces a transitive period with deep changes in the consumer market where the necessity to decarbonize the energy matrix requires a increasing participation of renewables in the crude oil refineries and the technology development like electric vehicles and 3 D printing have great potential to destroy transportation fuels demand, leading to deep changes in the production profile of crude oil refineries. Stricter regulations like IMO 2020 raises, even more, the relevance of the residue upgrading capacity to the competitiveness in the downstream industry, creating pressure over the refiners with low complexity refining hardware, in this sense, refiners with high capital investment capacity are looking for closer integration with petrochemical assets as a strategy to reduce costs and improve revenues.

Regarding the lubricating market, due to the accelerated technological development, especially in the automotive market, the Group I lubricating oil tend to lose market in the next years this fact tends to lead the refiners to look for capital investment aiming to sustain their competitiveness in the lubricating market.

As aforementioned, despite the high capital investment of the hydroprocessing units, the higher added value of the Groups II and III lubricants and the growing market can justify the investment mainly considering the trend of reduction in transportation fuels demand at a global level in the middle term that has been leading the refiners to look ways to ensure market share and revenues in the downstream industry through the maximization of high added value derivatives with the growing market as petrochemicals and lubricating oils.

Another side effect for lubricating producers based on solvent routes due to the competitiveness loss is raising the imports to supply the internal market, leading to an external dependence of critical production input as well as negative effects on the balance of payments.  This reinforce the relevance of capital investments in hydrocracking processing units as strategy to maximize the added value to crude oil reserves, especially considering the transition period faced by the downstream market where the petrochemicals tends to overpass transportation fuels as main driver of crude oil demand at global level.

Again, it’s important to understand the transitive period faced by the downstream industry and maintain competitive operations with the current focus in transportation fuels while the transition to petrochemicals is prepared in a sustainable manner aiming to keep economic sustainability and competitiveness in the downstream market, in other words, our current operations will sustain our desired future.

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Dr. Marcio Wagner da Silva is Process Engineering Manager at a Crude Oil Refinery based in São José dos Campos, Brazil. He earned a bachelor’s in chemical engineering from the University of Maringa (UEM), Brazil and a PhD. in Chemical Engineering from the University of Campinas (UNICAMP), Brazil. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking to bottom barrel units, moreover Dr. Marcio Wagner earned an MBA in Project Management from the Federal University of Rio de Janeiro (UFRJ), in Operations and Production Management at University of Sao Paulo (USP), and in Digital Transformation at Pontifical Catholic University of Rio Grande do Sul (PUC/RS), and is certified in Business from Getulio Vargas Foundation (FGV).