Unionfining The UOP RCD Unionfining process is a fixed-bed catalytic residue hydrotreating technology that reduces the contaminants in heavy feedstocks, such as • atmospheric residue, • vacuum residue, and • de-asphalted oil (DAO). Currently, the most common application of the RCD Unionfining process is FCC/RFCC feed pretreatment, in which approximately 90% of the sulfur and organo-metallics are removed. The process is also used for • production of low sulfur fuel oil and • partial conversion of non-distillables in the feed to distillables Process Description • The RCD reduced-crude desulfurization Unionfining process is a fixed-bed hydrogenation process that uses base metal catalysts to remove contaminants, such as sulfur, nitrogen,organometallics, and asphaltenes, and to increasethe hydrogen content of the products.The feedstock is first filtered before combining withhydrogen and passing through the catalyst beds atelevated temperatures and low space velocities.Because of the typical high contaminant levels, aguard bed reactor is used to control pressure dropassociated with large particles and solids that maybe in the residue feed. Often several reactors inseries are required because of the relatively lowreactivities of the feedstocks.The reactor effluent, which contains the products,recycle gas, and by-products, is then separated intothe desired products through a combination ofseparators, flash stages, and eventually, fractionationequipment. The hydrogen recycle gas requiresscrubbing to remove H2S. Then it is combined withmakeup gas before being recycled to the reactors(Figure 1). atmospheric hydrodesulphurization Among the available atmospheric residue hydrodesulphurization technologies, we can quote the RCD Unionfining™ process developed by UOP Company, the process Hyvahl™ by Axens Company, RCD Unionfining™ technology by UOP Company. the technology RHU™ by Shell Company, and the RDS™ technology commercialized by Lummus Company. atmospheric hydrodesulphurization 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 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. The main deactivation mechanisms of hydro processing catalysts are: 1. Metal deposition – Related to feedstock characteristics and drag of contaminants; 2. Active phase sintering process – Related to over temperature and metal deposition; 3. Coking deposition – Related to the processing conditions, feedstock characteristics, 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). The main deactivation mechanisms of hydro processing catalysts are: 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. • 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 • 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. • 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. • 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) 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. 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-DistillationHydrotreatment), 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 16 – Process Flow Diagram for H-Oil™ Process by Axens Company (FRECON et. al, 2019) 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. • 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. • Figure 18 – Process Flow Diagram for Uniflex™ Slurry Phase Hydrocracking Technology by UOP Company (UOP Company, 2019) 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 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. A guard-bed reactor A guard-bed reactor is a crucial component in many refining and petrochemicals processes. It acts as a protection system for downstream catalysts or equipment. By effectively eliminating impurities and contaminants from the process stream, guard-bed reactors enhance catalyst efficiency, extend catalyst lifespan, minimise deactivation risks, improve overall system reliability, and ultimately elevate the quality of the end product. This section also explores other types of reactor commonly used in refining and petrochemicals, and the advantages of fixed-bed reactors. The different types of reactors The different types of reactors used in refining and petrochemicals include • fixed-bed, • fluidized bed, • ebullated bed, and • guard-bed reactors. Fixed-bed reactors feature stationary catalyst beds, while fluidised-bed reactors suspend catalyst particles in a fluidising gas. Ebullated-bed reactors use a fluid-like catalyst bed with upward flow. Guard-bed reactors remove impurities before they reach the main catalyst bed. The advantages of a fixed-bed reactor The advantages of a fixed-bed reactor include high conversion and selectivity, improved heat transfer, continuous operation, and the flexibility to choose catalysts. These reactors ensure efficient contact between reactants and catalyst, resulting in enhanced reaction performance and reliable operation for a wide range of processes. One of the reasons for deactivation of hydrotreating catalysts is the poisoning by silicon compounds. The presence of silicon in petroleum fractions is caused by polydimethylsiloxanes (PDMS), which are added to increase the recovery of crude oil from the reservoir and as defoamers to avoid foaming in various processes, such as coking, visbreaking, steam cracking or distillation [1,2]. Total concentration of silicon can vary from a few hundred μg/kg to several mg/kg [3,4]. As it was shown in [5], thermal decomposition of PDMS results in the formation of cyclic siloxanes as the major products. The same situation was observed for PDMS degradation under thermal cracking of hydrocarbons [6,7]. The formed silicon species distillate from light to heavy petroleum cuts depending on their boiling points: the higher the boiling point, the greater molecular weight of cyclic siloxanes [8]. NiMo/Al2O3 are commonly used as the guard-bed catalysts from silicon poisoning [9]. In numerous works, silicon species are shown to adsorb strongly on a catalyst support and, after long time on stream, these species can reduce the accessibility of Ni-Mo-S sites for feed molecules resulting in the decrease in HDS activity. Silicon contamination has a strong negative impact especially on HDN activity and a negative impact on HDS activity [10,11]. Usually, a concentration below 15 wt% of SiO2 in a catalyst can be tolerated during the cycle of a commercial catalyst [12]. In catalysts with Al2O3 support, deposition of silicon species is an activated and diffusionally controlled reaction between silicon species and alumina OH groups. Silicon is adsorbed on the entire catalyst surface, resulting in surface, pore volume and active site losses. Hydrotreating Most products of crude and vacuum distillation in refineries contain a significant amount of sulfur that must be removed prior to further processing or use. Hydrotreating or hydrodesulfurization refers to a set of operations that remove • sulfur and • other impurities (Figure 1). During hydrotreating, crude oil cuts are selectively • reacted with hydrogen • in the presence of a catalyst • at relatively high temperatures and • moderate pressures. The process converts undesirable aromatics, olefins, nitrogen, metals, and organosulfur compounds into stabilized products. Some hydrotreated cuts may require additional processing to meet final product specifications. Hydrotreating is an efficient method to remove several compounds, including: • Sulfur is the most critical compound to remove. It is present in nearly all crude oil feedstocks as sulfur mercaptans, sulfides, disulfides, polysulfides, and thiophenes. • Nitrogen is typically treated with hydrogen gas and transformed into ammonia gas. • Oxygen is reacted with hydrogen and eliminated as water. Most oxygen in distillation cuts is not present as oxygen gas, but bonded to hydrocarbons. • Olefins are volatile and unstable, and they are not desirable in fuels. Olefins are transformed into stable paraffinic hydrocarbons. • Metals are removed because they can deposit on catalysts and in engines. The importance of hydrogen Hydrogen gas is one of the most important elements in the production of desulfurized fuels. For hydrotreating, the hydrogen stream • must be extremely pure (>99%) and have no humidity. • The stream should have a low hydrocarbon content, • as well as low mercaptan and hydrogen sulfide levels (<0.1%). Only • about 15–30% of the hydrogen demand of a refinery is produced internally by processes such as catalytic reforming of naphtha; • the rest is supplied by external producers . The industry uses a variety of terms for hydrogen that depend on how it was produced: Brown hydrogen is obtained from fossil fuels such as coal or lignite via gasification. Gasification has a large carbon footprint, but remains a common way to produce hydrogen. Gray hydrogen is obtained from natural gas via steam-methane reforming, and has a smaller carbon footprint than brown hydrogen. It has become the most common type of hydrogen due to low prices for natural gas. Blue hydrogen is commonly produced from methane, but differs from gray hydrogen in that the resulting carbon emissions are captured and sequestered. Due to environmental restrictions, blue hydrogen is becoming more common. Turquoise hydrogen is produced from a feedstock of pure methane via pyrolysis. It is associated with a very small carbon footprint, because pyrolysis byproducts include only solid carbon and no carbon dioxide. Green hydrogen is produced from any renewable energy source, such as electrolysis of water via windmills or solar energy. It has not gained traction due to technology challenges and high prices. Challenges and the future of hydrotreating Fuel consumption worldwide is increasing, putting pressure on refiners to increase production. Additionally, low-sulfur crude oils are becoming scarce, forcing refiners to contend with high-sulfur feedstocks while meeting increasingly tighter restrictions on sulfur concentrations in fuels. Addressing this compound challenge requires the development and application of catalyst technologies that improve • reaction rates, • conversion, and • overall performance of hydrotreating processes. Current catalysts suffer from selectivity issues that could be overcome by alternative technologies such as titanium dioxide and zirconium dioxide catalysts. Catalyst selectivity represents the ability of a catalyst to promote favorable reaction pathways that maximize the yield of desired products and minimize undesirable byproducts. Refineries typically operate at a hydrogen deficit, requiring purchase of hydrogen from outside vendors. Residue hydrotreating • Residue hydrotreating, also known as hydrodesulfurization, is a crucial process in petroleum refining. 1.Purpose: 1. The primary objective of residue hydrotreating is to reduce sulfur content in petroleum products. This is essential for meeting environmental regulations and improving fuel efficiency. 2. Traditionally, it focused on producing low-sulfur fuel oil (LSFO). as the demand for light transportation fuels (such as gasoline and diesel) rises, refiners now profit from converting resid (residual oil) into these lighter fuels. Residue hydrotreating 2. Process: 1. During residue hydrotreating, crude oil cuts (typically heavier fractions) are selectively reacted with hydrogen in the presence of a catalyst. 2. The process occurs at relatively high temperatures and moderate pressures. 3. Undesirable compounds (such as sulfur, nitrogen, and metals) are transformed into more stable products. 4. Sulfur, in particular, is chemisorbed in catalytic beds and can poison nickel catalysts if not removed. 5. The result is cleaner, more efficient fuels with reduced emissions of harmful compounds like NOx and SOx. Difference between hydrodesulfurization and hydrotreating: 2. Hydrotreating: 1. Hydrotreating is a broader term that encompasses both removal of • hydrodesulfurization and • other impurity processes. such as nitrogen, oxygen, and olefins. 2. During hydrotreating, crude oil cuts are selectively reacted with hydrogen in the presence of a catalyst at relatively high temperatures and moderate pressures. 3. The process converts undesirable compounds (aromatics, olefins, nitrogen, metals, and organosulfur compounds) into stabilized products. 4. Some hydrotreated cuts may require additional processing to meet final product specifications. Hydrodesulfurization (HDS), 1.Impurity Reduction: 1.By reducing sulfur content, HDS significantly reduces harmful combustion byproducts such as NOx and SOx. 2.These byproducts contribute to air pollution and acid rain, so minimizing them improves both environmental and human health. 2.Efficiency Gains: 1.When sulfur is present in fuels, it can poison catalysts used in downstream processes. 2.By removing sulfur through HDS, we enhance the effectiveness of catalysts during subsequent refining steps. 3.Efficient catalysts lead to better conversion rates, which ultimately improve fuel efficiency. 3.Meeting Standards: 1.HDS helps refineries meet final product specifications by reducing sulfur levels. 2.Contaminants can negatively impact downstream unit operations, catalysts, and engines. 3.For example, nickel catalysts are susceptible to sulfur poisoning, affecting their performance. Hydrotreating Hydrocracking Remove hetero atoms & saturate carbon‐carbon bonds • Sulfur, nitrogen, oxygen, & metals removed • Olefinic & aromatic bonds saturated Minimal cracking Minimal conversion – 10% to 20% typical Products suitable for further processing or final blending • Reforming, catalytic cracking, hydrocracking Selective catalysts for sulfur removal witho ut olefin saturation Severe form of hydroprocessing • Break carbon‐carbon bonds • Drastic reduction of molecular weight Reduce average molecular weight & produce higher yields of fuel products 50%+ conversion Products more appropriate for diesel than gasoline Feed stock must first be hydrotreated Hydrotreating Break only those bonds that allow removal of undesired atoms (sulfur, nitrogen, ….) Higher severity required to meet ultra low sulfur product specs Can also use to control wax formation tendencies Will tend to make some smaller molecules due to positon of sulfur in feedstock molecule Hydrocracking Typical feeds Cat cracker “cycle oil” • Highly aromatic with sulfur, small ring & polynuclear aromatics, catalyst fines; usually has high viscosity • Hydrocracked to form high yields of jet fuel, kerosene, diesel, & heating oil Gas oils from visbreaker • Aromatic Gas oil from the delayed coker • Aromatic, olefinic, with sulfur Hydrotreating/Hydrodesulfurization Most products of crude and vacuum distillation in refineries contain a significant amount of sulfur that must be removed prior to further processing or use. Hydrotreating or hydrodesulfurization refers to a set of operations that remove sulfur and other impurities (Figure 1). During hydrotreating, crude oil cuts are selectively reacted with hydrogen in the presence of a catalyst at relatively high temperatures and moderate pressures. Some hydrotreated cuts may require additional processing to meet final product specifications. This article explains the basics of hydrotreating processes, focusing on two of the most important petroleum products, naphtha and diesel oil. Hydrotreatment processes reduce • the impurity content of petroleum products, which increases the efficiency of the fuels and reduces the production of harmful combustion byproducts such as NOx and SOx (Fig. 2) Hydrotreating/Hydrodesulfurization Hydrotreatment also helps to satisfy final product specifications. Contaminants can affect the performance of downstream unit operations, catalysts, or even engines. Each hydrotreating unit is tailored to the feedstock and end product. For instance, the process to hydrotreat naphtha is not the same as the process for diesel fuels. The most common cuts that are hydrotreated in a refinery include: light naphtha, heavy naphtha, jet fuel or kerosene, and diesel oils (e.g., light and heavy coker diesel oil). The basics of hydrotreating It is common to assume that the hydrotreating process is a single unit operation that converts all of the raw feed into a final desulfurized product. However, this is not the case; most hydrotreatment processes require many unit operations, including a reactor, gas separators, separation columns, and heat exchangers. The process can be divided into three main processing blocks: 1. heat exchange network 2. reactor in which the actual hydrotreating takes place 3. stripping where the desulfurized product stream is separated from the volatiles, gases, and impurities. undesirable aromatics, olefins, nitrogen, metals, and organosulfur compounds Hydrotreating converts hydrogen sulfide, ammonia, water vapor stabilized products. The feed is first pressurized and mixed with the recycle and makeup hydrogen streams. The mixture is heated to about 290–430°C before entering the fixed-bed reactor, which operates at about 7–180 bar. Higher temperatures and pressures are used for processing heavier feedstocks, such as diesel oils. Overall, however, hydrotreater temperatures are relatively moderate, which avoids thermal cracking of molecules while being high enough to enable reaction of the feedstock. Inside the fixed-bed reactor, hydrogenolysis and mild hydrocracking reactions take place to convert sulfur, nitrogen, oxygen, and other contaminants to hydrogen sulfide, ammonia, water vapor, and other stabilized byproducts (Figure 3). If sulfur removal is the primary goal, cobalt-molybdenum catalysts are favored. Depending on the outlet streams, • conditions and • composition , the byproducts are either • discarded, • recycled, or • sent for further treatment. Reactor catalysts play a crucial role in final product development. If the crude oil is relatively low in sulfur, nitrogen removal becomes the priority and nickel-molybdenum catalysts are chosen. Hydrodesulfurization Sulfur Unsaturated carbon‐carbon bonds converted to hydrogen sulfide (H2S) • Added hydrogen breaks carbon‐sulfur bonds & saturates remaining hydrocarbon chains Form of sulfur bonds • Sulfur in naphtha generally mercaptans (thiols) & sulfides • In heavier feeds, more sulfur as disulphides & thiophenes Light ends • Heavier distillates make more light ends from breaking more complex sulfur molecules Olefins saturated – one hydrogen molecule added for each double bond • Olefins prevalent in cracked streams – coker or visbreaker naphtha, catalytic cracker cycle oil, catalytic cracker gasoline Aromatic rings hydrogenated to cycloparaffins (naphthenes) • Severe operation • Hydrogen consumption strong function of complexity of the aromatics • prevalent in heavy distillate hydrotreating, gas oil hydrotreating, hydrocracking Options for the refining industry-Residue Hydroprocessing 3 schemes offered by licensors: 1. Fixed bed hydrotreating, 2. ebullated/moving bed hydrocracking and 3. slurry phase hydrocracking.
