The Role of Hydroprocessing Technologies in the New Downstream Industry

Introduction and Context

One of the biggest challenges to the crude oil refining industry in the last decades is the development of technologies capable to reduce the environmental impact of the derivatives while raising the performance of these compounds. The hydroprocessing technologies allows the production of cleaner and better performance derivatives at same time that make possible the recovery of higher yields of added value products from bottom barrel streams in the crude oil refining.

The hydroprocessing technologies became essential to the downstream industry in the last decades once it’s practically impossible to produce marketable crude oil derivatives without at least one hydroprocessing step. To achieve the goal of ensure maximum added value to the processed crude oil, the refiners needs an adequate hydroprocessing capacity in this refining hardware, especially those processing heavier crude oils, the hydroprocessing catalysts are the heart of the hydroprocessing technologies and his relevance is increasingly high to the refiners.

Hydroprocessing Technologies – General 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 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.

           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. 

           Higher severity units, like process units dedicated to treating unstable streams (Light Cycle Oil, Coke Gas Oil, etc.) or with the objective to remove nitrogen or aromatics saturation, operates with two separating vessels like presented in Figure 2.

           In this case 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.  

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

For lower severity units the temperatures applied are about 300 to 350 oC and pressures varying between 20 to 40 bar, in addition of lower residence times. Units with high severity operate under temperatures 350 to 400 oC and pressures varying from 40 to 130 bar.  

Like aforementioned, great efforts was employed in the hydrotreating technology development, however, technology licensers like Axens, UOP, Exxon Mobil, McDermott, 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

           The hydrocracking process is a deep hydroprocessing technology where the hydrogenation reactions are conducted at same time of cracking reactions. Table presents the main differences between the hydrotreating and hydrocracking processes. 

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.

Among the feed streams normally processed in hydrocracking units are the vacuum gas oils, Light Cycle Oil (LCO), decanted oil, coke gas oils, etc. Some of these streams would be hard to process in Fluid Catalytic Cracking Units (FCCU) because of the high contaminants content and the higher carbon residue, wich quickly deactivates the catalyst, in the hydrocracking process the presence of hydrogen minimize these effects.

Figure 3 shows a typical arrangement for hydrocracking process unit with two reactions stages, dedicated to producing medium distilled products (diesel and kerosene). 

Figure 3 – Basic Process Flow Diagram for Two-stage Hydrocracking Units

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

Atmospheric Residue Desulfurization – An Especial Case

With the start the validity of the new regulation over the quality parameters of marine fuel oil (BUNKER), some refiners and crude oil producers still question what will be the market behavior face to the new regulation. The IMO 2020 requires a deep reduction in the sulfur content of the marine fuel oil from the current 3,50 % in mass to 0,50 % in mass, leading to a necessity of changes in the production process of this derivative or higher control of sulfur content in the processed crude slate by the refiners.  

           To refiners with adequate bottom barrel processing capacity, the new regulation tends to don’t be a great threat and can represent a good opportunity to raise the profitability, taking into account the competitive advantage which the high complexity refining hardware gives to these refiners. The eventual devaluation of high sulfur crude oil can suffer due to the IMO 2020 can be translated in higher refining margins to refiners capable to process these crudes.   

           One of the technologies that have been widely considered in the downstream industry in the IMO 2020 scenario the desulphurization of atmospheric residue, aiming to allow not only the compliance with the new regulation but the quality improvement of the other derivatives and reliability of the downstream process units like FCC or hydrocracking. As presented in Figure 4, the atmospheric residue corresponds to the bottom stream of the atmospheric crude oil distillation column.

Figure 4 – Typical Process Arrangement of Atmospheric Crude Oil Distillation Unit

Once heteroatoms like sulfur, nitrogen, and metals tend to concentrate in the heavier fractions of the crude oil, the atmospheric residue drags a major part of the contaminants present in the crude oil. Considering the current quality and environmental requirements over the derivatives, posterior treatments are required aiming to reduce the contaminants content (mainly sulfur and nitrogen) in the derivatives.  

Before January of 2020, the production of marine fuel oil (BUNKER) involves basically the dilution of vacuum residue (bottom barrel stream from vacuum distillation column) or deasphalted oil (to refiners that rely on solvent deasphalting unit in the refining scheme) with lighter streams like LCO (Light Cycle Oil) and gas oils, as presented in Figure 5. 

Figure 5 – Marine Fuel Oil (BUNKER) Production Process Before IMO 2020

The IMO 2020 makes necessary a better control of the sulfur content in the streams applied as diluents in the BUNKER production, to refiners with high bottom barrel conversion capacity the control of the sulfur content in the vacuum residue through the atmospheric residue applying hydrodesulphurization minimizes the necessity of treatment of other streams as well as can avoid the use of noblest streams like diesel and jet fuel as diluents in the BUNKER production.

The hydrodesulphurization process of atmospheric residue presents additional technologic challenges when compared with the hydrotreating process applied to final derivatives like diesel and gasoline, taking into account the high contaminants content, mainly metals, and the residual carbon due to the high concentration of resins and asphaltenes in the feedstream. Beyond the sulfur removal, the main goal, the atmospheric residue hydrodesulphurization unit promotes the partial removal of metals, nitrogen and residual carbon (CCR) through catalytic hydrogenation mechanism.

Among the available atmospheric residue hydrodesulphurization technologies, we can quote the RCD Unionfining™ process developed by UOP Company, the process Hyvahl™ by Axens Company, the technology RHU™ by Shell Company, and the RDS™ technology commercialized by Lummus Company.   

           Figure 6 present the basic process flow diagram for the RCD Unionfining™ technology by UOP Company. 

Figure 6 – UOP RCD Unionfining™ Atmospheric Residue Hydrodesulphurization Technology (UOP Company Website, 2019)

The role of the atmospheric hydrodesulphurization unit in the refinery goes beyond allowing the production of low sulfur fuel oil, in high complexity refineries the unit is applied as feedstock treatment step to conversion units as FCC/RFCC, hydrocracking, and delayed coking. The reduction of contaminants content and residual carbon promoted by the atmospheric residue hydrodesuphurization unit significantly raises the quality of derivatives produced by downstream units as well as raises the catalyst lifecycle of deep conversion processes like FCC and hydrocracking, contributing to reduce the operation costs.  

The process conditions tend to be more severe in the case of atmospheric residue hydroprocessing. The feedstock characteristics lead to a strong tendency of coke deposition over the catalyst requiring then higher hydrogen partial pressure (until 180 bar to fixed bed reactors) as well as higher temperatures (380 to 420 oC).

The hydrotreating process of atmospheric residue is normally conducted in fixed bed reactors and the most employed catalysts are Cobalt (Co), Nickel (Ni), Molybdenum (Mo), and Tungsten (W), normally in association between them and supported over alumina (Al2O3).  The combination Co/Mo is normally more active to hydrodesulphurization reactions while the Ni/Mo combination is responsible for hydrodenitrogenation and aromatics saturation reactions.

A typical atmospheric residue hydrodesulphurization unit can achieve 95 % of conversion in hydrodesulphurization reactions and 98 % in hydrodemetallization reactions, furthermore, it’s possible to achieve a reduction of 65 % in residual carbon according to the employed technology. Normally, atmospheric hydrodesulphurization units rely on catalytic beds focused to remove metals also called guard beds aiming to protect the catalysts in the downstream reactors and improve the operational lifecycle.

Due to the severe operating conditions, the operation costs of atmospheric residue desulphurization units are higher when compared with hydrotreating units dedicated to processing distillates (Diesel, Jet fuel, and Naphtha). The most intense hydrogenation process leads to a necessity of more robust quenching systems of catalytic beds, higher hydrogen make-up rates and more complex phase separation systems (multiple stages).  

The Challenges of Renewables Processing in Hydrotreating Units – The Hydrogen Matter

Despite the advantages of environmental footprint reduction of the refining industry operations, renewables processing presents some technological challenges to refiners. Figure 7 presents the chemical mechanism for the processing of vegetable/animal oils in hydrotreating units. 

Figure 7 – 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.

Refiners and technology developers are looking for alternatives to produce hydrogen in industrial scale with lower CO2 emissions and some attractive routes have been considered as competitive in the future, as presented in Figure 8.

Figure 8 – Hydrogen Lifecycle and Potential Applications (Technip Company, 2020)

Despite the advantages of the green production routes of hydrogen, they are still in development and poor attractive to the most part of the refiners, in the current scenario the refiners to look for more efficient operations aiming to optimize the hydrogen balance the refining hardware as well as apply CO2 capture technologies (the blue route), in this sense an attractive alternative is to apply technologies capable to recovery hydrogen from refinery off-gases and apply control strategies capable to minimize the hydrogen losses to flare system.

           As exposed above the hydrogen generation is a key matter to refiners, and refineries that rely on Catalytic Reforming units apply the hydrogen produced in this process unit to compose a relevant part of the hydrogen network becoming an important internal source of hydrogen. In some markets, where the demand by petrochemicals is lower, the main relevance of the catalytic reforming to the refining hardware is the hydrogen generation against the production of light aromatics. Figure 9 presents an example of hydrogen network in a crude oil refinery with high hydroprocessing capacity.

Figure 9 – Example of Hydrogen Network to a Crude Oil Refinery (LAFLEUR, 2017)

           In refineries with bottlenecked hydrogen generation units, the hydrogen from catalytic reforming units is fundamental to ensure the compliance with the current quality and environmental regulations, becoming a fundamental enabler to profitable and reliable operations of the refining hardware. Nowadays, it’s not uncommon to find refiners operating catalytic reforming units with the main objective to hydrogen generation, especially to refiners that operates with octane giveaway in the gasoline pool.

Hydroprocessing Catalysts

The hydrotreating catalysts are normally composed by metal sulfides of Group VI (W and Mo) or/and Group VIII (Ni and Co) carried by an oxide like alumina, zeolite or silica-alumina. The most employed combinations in traditional hydrotreating processes are Co/Mo (Cobalt/Molybdenum), Ni/Mo (Nickel/Molybdenum), and Ni/W (Nickel/Tungsten). The combination Co/Mo is normally applied to hydrodesulfurization reactions once presents less activity to harder reactions as hydrodenitrogenation or aromatics saturation, in these cases the catalyst selected is based on Ni/Mo combination while the Ni/W catalysts is applied to deep hydroprocessing processes where the main objective is aromatics saturation. Normally, the hydroprocessing reactors are filled with a combination of these catalysts aiming to optimize the performance and operating costs.

Some promoters can be added to the hydrotreating catalysts aiming to improve the performance in specific cases. Phosphorous is added to the Ni/Mo catalysts with the objective to improve the hydrodenitrogenation activity and the Fluor is applied to improve the catalyst performance in cracking reactions through the higher acidity in the carrier, this is a great advantage in mild hydrocracking processes.

Catalysts applied in hydrocracking processes can be amorphous (alumina and silica-alumina) and crystallines (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 exothermic and the hydrogenation reactions are endothermic, 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 characteristic, the hydrocracking global process is exothermic and the reaction temperature control is normally made through cold hydrogen injection between the catalytic beds.

           To hydrocracking units, the catalyst activity is defined by the required temperature to reach a desired conversion, which is defined by Equation 1.

 Conversion (%) = [(1 – (Fraction with Above TBP in the Product)/ (Fraction with Above TBP in the Feed))] x 100  (1)  

Where TBP is True Boiling Point, which represents the desired cut point defined by the refiner.

Deactivation of Hydroprocessing Catalysts

           The main deactivation mechanisms of hydroprocessing catalysts are:

·      Metal deposition – Related to feedstock characterists and drag of contaminants;

·      Active phase sintering process – Related to over temperature and metal deposition;

·      Coking deposition – Related to the processing conditions, feedstock characterists, and operating issues. Is considered the only reversible deactivation process.

The metals deposition is mainly affected by Ni, V, Pb, As, Si, Fe, and Na. Nickel and Vanadium can be present is heavier fractions of crude oil and plug the catalysts pore and act as coke precursors. Lead (Pb) and Arsenic (As) can react with the active phases (metal sulfides) leading to sintering process and consequently reduction of active phase area, Pb is find in naphtha fractions and the Arsenic can be found in all petroleum fractions.

Contamination by silicon occurs normally due to the injection of silicon based compounds in the crude oil extraction step and in downstream processes like Delayed Coking units where are applied anti-foaming agent. The silicon acts reducing the surface area and plugging the catalyst pore, leading to a severe activity reduction. The deactivation by sodium (Na) is similar of the silicon (Si) process, in hydrocracking processes the feed contamination by sodium is a great concern once the basic character of sodium promote the neutralization of acid function of the hydrocracking catalysts, leading to a drastic reduction in the conversion (Equation 1).

Coking deposition is related to condensation of high weight molecules (heavier aromatics and asphaltenes) present in heavier feeds. The coke deposition is also related with dehydrogenation, cracking, and polymerization reaction of heavier fractions, the deactivation occurs through the plugging of catalysts pores blocking the mass transfer from the hydrocarbon to the active phase, as presented in Figure 10. 

Figure 10 – Reactants and Products Flows in a Generic Porous Catalyst (GONZALEZ, 2003)

           The coking deposition also reduces the active surface area and is normally followed by metals deactivation, mainly to hydroprocessing units dedicated to treat bottom barrel streams.

           The Coking deposition process is positively affected by temperature and negatively affected by hydrogen partial pressure, by this reason, hydroprocessing units dedicated to process heavier feeds operates under higher pressures with the main objective to protect the catalysts that are responsible by great part of operating costs of the refiners.

           In severe hydrocracking units, can be observed an inhibition effect of the NH3 over the catalysts due to the acid function neutralization, in these cases this issue is minimized through the gas separation between the reaction stages, as presented in Figure 11.

Figure 11 – Typical Arrangement for Two Stage Hydrocracking Units with Intermediate Gas Separation

           The activity of hydrotreating catalysts is monitored through the temperature required to reach desired contaminant content (normally sulfur) in the product being the maximum temperature limited by the metallurgy limits of the material applied in the design of the hydroprocessing unit.

           The most known technology developers of hydroprocessing catalyst are Haldor Topsoe, Albemarle, ExxonMobil, UOP, Advance Refining Technologies (ART) Company, Criterion, Chevron Lummus Global (CLG), and Shell Catalysts Company.

How to Control the Pressure Drop in Fixed Bed Hydrotreaters?

           The main causes of high pressure drop in hydroprocessing reactors are the internals like distributors and trays, particulates which are normally dragged with the feedstock, organic species like olefins and asphaltenes, and the coking deposition related to low hydrogen partial pressure, inadequate distribution or hot points in the catalyst bed. Nowadays, the increasing participation of renewable raw material in hydrotreating reactors calls for even more attention due to the higher heat release, concentration of chemical unstable components, and higher total acid number.

           Among the available strategies to mitigate the pressure drop issue in fixed bed hydroprocessing reactors, it’s possible to quote:

·      Filtration of the feedstock – This strategy is especially important to feeds from delayed coking units due to the presence of coke particulates;

·      Antifouling dosage in the hydroprocessing unit – The main objective here is control the corrosive process, avoiding the drag of corrosion material to the reactors;

·      Sacrificial Catalysts – This strategy is applied mainly in hydrotreating units dedicated to processing bottom barrel streams, it’s applied a high porosity catalyst to act as a filter, retaining particulates and contaminants in the top of the catalyst bed;

·      Grading Catalyst – The grading is applied to retain the contaminants in the first section of the bed through the application of non-active material.

The size and shape of the catalyst particles have great effect over the pressure drop in the hydroprocessing reactor as well as the catalyst load strategy affects the pressure drop in the bed, aiming to improve the characteristics of the catalyst, the Criterion Company develop the ATX™ catalyst shape which, among other characteristics, can minimize the pressure drop in the catalyst bed. In dense load, one of the critical parameters is control the load speed to avoid the catalyst cracking during the load, raising the fines production.

During the startup of the hydroprocessing units it’s important to analyze the procedures in order to avoid great quantity of liquid in the catalyst beds during the startup, the high quantity of liquid can vaporize abruptly during the final steps of the startup, leading to the catalyst broken and high pressure drop.

           As aforementioned, control the catalyst lifecycle is a key issue to refiners and one of the main strategies adopted in the last years is the use of guard beds in hydroprocessing catalysts to protect the catalysts, ensuring longer and most profitable operating campaign.

           The main objective of the guard bed is to protect the main and active catalyst against:

·      Particulates from the feedstock that can be dragged like sediments, catalysts powder and corrosion products that are capable to produce physical fouling;

·      Heavier hydrocarbons capable to lead of coking deposition;

·      Chemical unstable hydrocarbons capable to produce gum, like olefins and diolefins;

·      Metals and catalysts poisons like Ni, V, Fe, Si, Na, etc.

As aforementioned, due to the higher concentration of contaminants the guard beds are most common in hydroprocessing units dedicated to processing heavier feedstocks, as quoted above. Normally is applied a grading strategy in the catalyst bed aiming to establish an staggering of pore diameter and activity to the catalysts, keeping the catalysts in the top more resistant to the contaminants acting as a filter, protecting then the most active catalyst in the bottom section, Figure 12 presents an example of hydroprocessing catalysts grading according to STAX™ technology by Albemarle Company.

Figure 12 – Example of Hydroprocessing Catalyts Grading (LELIVELD & TOSHIMA, 2015)

           In Figure 12, the guard bed will be responsible to control the contaminants content (mainly metals) to the next catalyst sections as well as to reduce the carbon residue (CCR) and particulates concentration, keeping the activity and improving the lifecycle of the hydroprocessing unit.

           Among the most known catalyst protection technologies available in the market, we can quote the CatTrap™ technology developed by Crystaphase Company, this technology applies a ceramic bed acting as a filter to particulate materials, controlling especially the pressure drop in the catalyst bed. 

           For units dedicated to treat bottom barrel streams, the hydroprocessing catalyst needs present high activity and be resistant to the high contaminants content (sulfur, nitrogen, and silicon), some companies have been dedicated his efforts to develop catalytic systems capable to attend these requirements, as examples of these technologies we can quote the START™ system by Advanced Refining Technologies (ART) Company, the UNITY™ system developed by UOP Company, the SENTRY™ catalysts by Criterion Catalysts Company, and the TK-449 Silicon Trap™ by Haldor Topsoe Company. Figure 13 presents a comparative study developed by Haldor Topsoe Company related to the improvement of the cycle length of a naphtha hydrotreating unit applying grading particles to control the contaminants content over the main catalyst.

Figure 13 – Cycle Length Improvement in a Naphtha Hydrotreating Unit with Catalyst Grading (Haldor Topsoe Company, 2020)

           The increasing relevance of the hydroprocessing technologies to the downstream industry requires even more attention from refineries aiming to keep profitable and reliable operations in these units, the guard beds technologies have an important role to allow the achievement of this goal, as presented in Figure 13 these technologies can improve in a significant manner the operational lifecycle of the hydroprocessing units.

Processing Extra Heavy Crudes – The Deep 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 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 14 shows a schematic diagram of the residue upgrading technologies applied according to the metals and asphaltenes content in the feed stream. 

Figure 14 – 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.

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.

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 15 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 16.

Figure 15 – 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 16 – 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 17 presents a basic process flow diagram for the VCC™ technology by KBR Company.

Figure 17 – 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 18 presents a basic process flow diagram for the Uniflex™ slurry hydrocracking technology by UOP Company.

Figure 18 – Process Flow Diagram for Uniflex™ Slurry Phase Hydrocracking Technology by UOP Company (UOP Company, 2019)

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.

The 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 19.

Figure 19 – 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 18, 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.

The antifragile profile is related to options and refiners with more operational flexibility have more options available to decide how crude oil slate will be processed and what kind of derivatives will be maximized in compliance with market demand and to achieve better economic results. In this sense, considering the recent forecasts, a combination of adequate bottom barrel conversion capacity and petrochemicals maximization seems capable to offer antifragile characteristics to the players of modern downstream industry.

Conclusion

           The hydroprocessing technologies became essential to refiners in the last decades once is practically impossible to produce marketable crude oil derivatives without at least one hydroprocessing step, even to refiners processing lighter crudes. Hydroprocessing units have a fundamental role in the downstream industry not only in the economic sustainability of the industry but to keep under acceptable levels the environmental impact of the crude oil derivatives, in this sense, an adequate management of hydroprocessing catalysts is a key factor to ensure lower operating costs and competitiveness to refiners in the downstream market.

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.

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Dr. Marcio Wagner da Silva is Process Engineer and Project Manager focusing on Crude Oil Refining Industry based in São José dos Campos, Brazil. Bachelor’s 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), in Digital Transformation at PUC/RS, and is certified in Business from Getulio Vargas Foundation (FGV).