Improving the Residue Upgrading Capacity in the Refining Hardware with Less Capital Spending – Synergies of Carbon Rejection Technologies

Introduction and Context

Nowadays, the capacity to add value to the bottom barrel streams represents a great competitive advantage among refiners, especially considering the stricter regulations as IMO 2020 that imposes a significant reduction in the sulfur content of marine fuel oils (BUNKER), requiring even more capacity to treat bottom barrel streams, especially to refiners processing heavier crude oils.

In this scenario, process units called a bottom barrel, able to improve the quality of crude oil residue streams (Vacuum residue, Gas oils, etc.) or convert them to higher added value products gain strategic importance, mainly in countries that have large heavy crude oil reserves. These process units are fundamental to comply with the environmental and quality regulations, as well as to ensure the profitability and competitiveness of refiners through raising the refining margin.

Available technologies to processing bottom barrel streams involve processes that aim to raise the H/C relation in the molecule, either through reducing the carbon quantity (processes based on carbon rejection) or through hydrogen addition. Technologies that involve hydrogen addition encompass hydrotreating and hydrocracking processes while technologies based on carbon rejection refer to thermal cracking processes like Visbreaking, Delayed Coking, and Fluid Coking, catalytic cracking processes like Fluid Catalytic Cracking (FCC), and physical separation processes like Solvent Deasphalting units. Some refining schemes can apply the synergy between residue upgrading technologies aiming to ensure higher added value to the processed crude oils as well as meet the regulations and ensure higher refining margins in the downstream sector, an interesting case is the combination of Solvent Deasphalting, Fluid Catalytic Cracking, and Delayed Coking Technologies, all based on carbon rejection, as a strategy to improve the refinery capacity to add value to bottom barrel streams. This alternative offers a low capital spending route to reduce the production of low added value derivatives in the refining hardware as the high sulfur fuel oil when compared with deep conversion units based on hydrogen addition like hydrocracking units, Figure 1 presents a comparative study of the residue upgrading alternatives based on capital investment.

Figure 1 – Capital Spending x Residue Conversion to Residue Upgrading Technologies (Shell Catalysts and Technologies, 2019)

As presented in Figure 1, 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. The choice of adequate residue upgrading capacity needs to take into account several factors, including the quality of the available crude oil, the capacity of capital investment, and operational costs. Despite the limitations of the carbon rejection technologies, refiners processing middle and relatively low sulfur crude oils can apply these technologies to upgrade residues and maximize their refining margins in a less capital spending way.

Solvent Deasphalting Technologies

The typical feedstock for deasphalting units is the residue from vacuum distillation that contains the heavier fractions of the crude oil. The residue stability depends on of equilibrium among resins and asphaltenes, once which they resins solubilize the asphaltenes, keeping a dispersed phase.

The deasphalting process is based on liquid-liquid extraction operation where is applied light paraffin (propane, butane, pentane, etc.) to promotes resins solubilization inducing the asphaltenes precipitation, that correspond to the heavier fraction of the vacuum residue and concentrate the major part of the contaminants and heteroatoms (nitrogen, sulfur, metals, etc.). The process produces a heavy stream with low contaminants content called deasphalted oil (Extract phase) and a stream poor in a solvent containing the heavier compounds and with high contaminants content, mainly sulfur, nitrogen and metals called asphaltic residue (Raffinate phase).

           Figure 2 shows a basic process flow diagram for a typical process deasphalting unit. 

Figure 2 – Typical Arrangement for a Solvent Deasphalting Process Unit 

The vacuum residue is fed to the extracting tower where occurs the contact with the solvent leading to the solubilization of the saturated compound, in the sequence, the mixture solvent/vacuum residue is sent to separation vessels where occurs the separation of asphaltic residue from deasphalted oil, as well as the solvent recovery.

The choice of solvent employed has fundamental importance to the deasphalting process, solvents that have higher molar mass (higher carbon chain) presents higher solvency power and raise the yield of deasphalted oil, however, these solvents are less selective and the quality of the deasphalted oil is reduced once heavier resins are solubilized which leads to a higher quantity of residual carbon in the deasphalted oil, consequently the content of the contaminants raises too. As normally the deasphalting unit aims to minimize the carbon residue, metals, and heteroatoms in the deasphalted oil, propane is the usual solvent applied, mainly when the deasphalting process role in the refining scheme is to prepare feed streams for catalytic conversion processes.

The main operational variables of the deasphalting process are feedstock quality, solvent composition, the relation solvent/feedstream, extraction temperature, and temperature gradient in the extraction tower. Despite being a very important variable the extraction pressure is defined in the unit design step and is normally defined as the need pressure to keep the solvent in the liquid phase, in the propane case the pressure in the extraction tower is close to 40 bar.

Feedstock quality depends on crude oil characteristics processed by the refinery, as well as the vacuum distillation process. Depending on the fractionating produced in the vacuum distillation unit the vacuum residue can be heavier or lighter, affecting directly the deasphalting unit yield. Using propane as solvent the relation solvent/feedstream is close to 8 and the feed temperature in the extraction tower is close to 70 oC.

In refineries focused on fuels production (mainly LPG and gasoline), the deasphalted oil stream is normally sent to the Fluid Catalytic Cracking Unit (FCCU), in this case, the contaminants content and carbon residue needs to be severely controlled to avoid premature deactivation of the catalyst which is very sensitive to metals and nitrogen. In refineries dedicated to producing middle distillates, the deasphalted oil can be directed to hydrocracking units.

When the deasphalting process is installed in refining units dedicated to producing lubricants, the quality of deasphalted oil tends to be superior in view that the crude oil processed is normally lighter and with lower contaminant content. In this case, the deasphalted oil is directed to the aromatic extraction unit or to hydrotreatment/hydrocracking units, in the last case, the deasphalted oil quality is more critical because of the possibility of premature catalyst deactivation.

The asphaltic residue stream is sent to the fuel oil pool after dilution with lighter compounds (gas oils) or the stream can be used to produce asphalt. Another possibility is to send the asphaltic residue to a Delayed Coking Unit. As the aromatics content in the asphaltic residue is high, the coke produced presents very good quality.

The principal step in the solvent deasphalting process is the liquid-liquid extraction which depends on strength of the solvent properties, in this sense, some licensors developed deasphalting processes based on the solvent in supercritical conditions. Above critical point, the solvent properties are more favorable to the extraction process, mainly solvency power and the vaporization and compression facility, which reduce the power consumption in the process.

The processes ROSE? licensed by KBR Company, UOP-DEMEX? licensed by UOP and the process SOLVAHL? licensed by AXENS are examples of deasphalting technologies in supercritical conditions.

In addition to the cited processes, the FOSTER WHEELER Company in partnership with UOP developed the process UOP/FW-SDA? which applies solvent in supercritical conditions too.

Like described earlier, the deasphalting process allows add value to residual streams as vacuum residue and, consequently, raises the refiners profitability furthermore the process can help in the production of higher quality and cleaner derivates.

As another residue upgrading technologies, the deasphalting process raises the refinery flexibility regarding the quality of crude oil processed, that can pass to process heavier crude oils that have normally lower cost, and this fact can improve the refining margin.

Currently, the deasphalting technology has lost ground in the more modern refining schemes to Delayed Coking units since these units can process residual streams producing streams that can be converted into products with high added value (LPG, Gasoline, and Diesel), without the need of previous feed stream treatment to remove contaminants. However, the products from delayed coking units need hydrotreatment to be commercialized which raises significantly the operational and installation costs to the refinery. In some refining schemes, the deasphalting and delayed coking units can be complementary technologies, like the aforementioned.

The choice of residue upgrading technology by the refiners normally involves an economic analysis that takes into account the refinery production focus (middle distillates, light products, or lubricants), the market that will be served, and the synergy among the processes that will be applied in the adopted refining scheme.

Delayed Coking Technologies – General Overview

Delayed coking employs the thermal cracking concept under controlled conditions to produce light and middle streams (LPG, naphtha, and gas oils) from residual streams which would normally be used as diluents in fuel oils production.  

The typical feed stream for delayed coking units is the residue from the vacuum distillation process that contains the heavier fractions of processed crude oil, however, streams like decanted oil from FCC unit and asphaltic residue produced in solvent deasphalting can compose the feed stream to the delayed coking unit, depending upon the refining scheme adopted by the refiner. Another possibility is to send the residue from atmospheric distillation directly to the delayed coking unit, in this case, the unit design is quite modified demanding greater robustness of the fractionating and gas compression section.

Due to the thermal cracking characteristics (low availability of hydrogen during the reactions), the streams produced by the delayed coking units have a high concentration in olefinic compounds, which are chemically unstable.  Furthermore, due to the processing of residual streams that have high contaminant content like nitrogen, sulfur, and metals, therefore the refiners that apply delayed coking units need high hydrotreating capacity to convert these streams into added value products and that meets the level of the contaminants according to the environmental regulation.  

        Figure 3 presents the process flow scheme for a typical delayed coking unit.  

Figure 3 – Typical Arrangement for Delayed Coking Unit 

The feed stream is fed into the bottom of the main fractionating tower where is mixed with the heavier fraction of the thermal cracking products and then sent to the fired heater where thermal cracking reactions are initiated, the reaction conditions are controlled so that the reactions are completed in the coke drums, the residence time in the fired heater must be the lowest possible to minimize the coke precipitation in the fired heater tubes. A manner of minimizing the coke formation in the walls of tubes is the steam injection that raises the velocity and consequently reduces the residence time.  

After the fired heater the feed stream is sent to the coke drum or reactor, where the thermal reactions are completed and the coke is deposited. The thermal cracking products are removed from the top of the reactor and receive an injection of quench with a cold process stream (normally heavy or middle gas oil) and directed to the main fractionators where the products are separated. The coke deposited in the reactor is removed through a cut with water under high pressure (about 250 bars).

Delayed coking is a process that occurs in batch, in order to make a semi-continuous process are always employed in pairs numbers of reactors and every two reactors are applied one fired heater when one reactor is under reaction the other is in decoking step and so on. The delayed coking process occurs in cycles that can vary from 14 to 24 hours.

The main operational variables of the delayed coking unit are recycled ratio which is the quantity of the total feed stream which corresponds to the heavier fraction of the reaction products that are mixed with the fresh feed, reactor temperature, normally considered in the top of the coke drum, pressure in the top of the reactor and the time of the reactor cycle.  

The recycle ratio vary normally between 5 to 10% (to units dedicated to producing fuels) and the refiners seek to operate the unit with de lower recycle ratio possible in order to maximize the capacity of the plant in processing residual streams. The reactor temperature is close to 430 oC and is linked with the fired heater temperature, throughout the thermal cracking reactions the temperature fall due to the endothermic characteristics of the reactions.

The pressure in the reactor can vary between 1 to 3,5 bars, in units optimized to producing fuels the variable is maintained at lower levels, on the other hand, when the unit is dedicated to producing high-quality coke, the unit is operated under higher pressures.

Reactor cycle time is linked to the function performed by the delayed coking in the refining scheme. Units dedicated to producing fuels operate at shorter cycles and units optimized to producing high-quality coke operate under longer cycles.

The coke produced normally is seen as a by-product of the delayed coking unit, however, in some cases, the delayed coking process is optimized to producing high-quality coke and the coke becomes the principal product of the process.

Depending on the feedstock quality that will be processed, three types of coke can be produced:

·        Shot coke – Poor quality coke produced from feedstock with high asphaltenes and contaminants (sulfur, nitrogen, and metals) content, normally this type of coke is commercialized as fuel;

·        Sponge coke – In this case, the feedstock has a lower asphaltenes and contaminants content and the coke can be directed to raw material to the anodes production process to the aluminum industry; 

·        Needle Coke – The production of this type of coke requires the processing of feedstock with high aromatics content (decanted oil from FCC, for example) and these products are sent as raw material to producing anodes to the steel industry; 

As mentioned above, the production of high-quality coke requires quality control of the feed stream that will be processed, in most cases the refiners choose to install delayed coking units focusing on the production of middle and light distillates. Therefore, unit optimization to produce needle coke occurs only in specific cases.  

Figure 4 shows a delayed coking main fractionator scheme with the principal process streams.  

Figure 4 – Main Fractionator Scheme for a Typical Delayed Coking Unit 

The heavy gas oil stream is normally directed to the fluid catalytic cracking unit or can be utilized as fuel oil, in refining schemes that have deep hydrocracking units this stream can be used as feedstock to the unit. The sending of this stream to the fluid catalytic cracking unit needs to be controlled to avoid the premature deactivation of the catalyst, face of the high level of contaminants, mainly nitrogen and metals. 

           Middle and light gas oils are normally sent to severe hydrotreating units to compose the diesel pool of the refinery. The heavy coker naphtha can be directed like feed stream to FCC units. When the flashpoint specification of diesel is not restricted this stream can be sent to the diesel pool, after a deep hydrotreating process.

           The lighter fraction of naphtha can be sent to the gasoline pool of the refinery after hydrotreatment or directed to FCC units, in this case, this stream contributes to raising de LPG production in the FCC unit. In some cases, the light coker naphtha can be sent to catalytic reforming units aiming to produce high octane gasoline or petrochemical precursors (benzene, toluene, and xylenes).

           The overhead products from the main fractionator are still in the gaseous phase and are sent to the gas separation section. The fuel gas is sent to the refinery fuel gas ring, after treatment to remove H2S, where will be burned in fired heaters while the LPG is directed to treatment and further commercialization.

Figure 5 presents a typical scheme for a gas separation section for a delayed conking unit. 

Figure 5 – Basic Process Flow Diagram for a Typical Gas Separation Section from Delayed Coking Unit 

The main licensers for delayed coking technology nowadays are the companies FOSTER WHEELER?, CONOCOPHILLIPS ?, LUMMUS?, and KBR?.

           Delayed coking technology becomes especially attractive for refiners installed in countries with large heavy and extra-heavy crude oil reserves, like Brazil, Mexico, and Venezuela. The use of delayed coking in the refining scheme can minimize the production of low added value products like fuel oils and guarantees higher flexibility to the refinery in a relation to processed crude oil, minimizing the necessity to acquire light oils.

           On the other hand, the delayed coking technology obliges the refiners the necessity of high hydrotreatment capacity once the streams produced by the unity needs severe treating process before being sent to the commercialization, this fact can raise the operational and installations costs.

           Another delayed coking disadvantage is the necessity of handling, storage, and commercialization of coke which normally are not the focus of the refiners.  Some variations of coking technology as FLUID COKING? e FLEXICOKING?, the last licensed by ExxonMobil? Company, can minimize or eliminate the coke formation during the oil residual streams upgrading.  

Fluid Catalytic Cracking Technologies

The installation of catalytic cracking units allows the refiners to process heavier crude oils and consequently cheaper, raising the refining margin, mainly in higher crude oil prices scenario or in geopolitics crises that can become difficult the access to light oils.  The typical Catalytic Cracking Unit feedstream is gas oils from the vacuum distillation process. However, some variations are found in some refineries, like sending heavy coke naphtha, coke gas oils, and deasphalted oils from deasphalting units to processing in the FCC unit.

In a conventional scheme, the catalyst regeneration process consists of the carbon partial burning deposited over the catalyst, according to the chemical reaction below:

C + ? O2 → CO

The carbon monoxide is burned in a boiler capable of generating higher pressure steam that supplies other process units in the refinery. Figure 6 presents a process scheme for a typical Fluid Catalytic Cracking Unit (FCCU).  

Figure 6 – Schematic Process Flow for a Typical Fluid Catalytic Cracking Process Unit (FCCU) 

The principal operational variables in a fluid catalytic cracking unit are reaction temperature, normally considered the temperature in the top of the reactor (called riser), feed stream temperature, feed stream quality (mainly carbon residue), feed stream flow rate, and catalyst quality. Feedstock quality is especially relevant, but this variable is a function of the crude oil processed by the refinery, so is difficult can be changed, but for example, aromatic feedstock’s with high metals content are refractory to cracking and conducting to quick catalyst deactivation.

An important variation of the fluid catalytic cracking technology is the residue fluid catalytic cracking unit (RFCC). In this case, the feedstock to the process is basically residue from the atmospheric distillation column, due to the high carbon residue and contaminants (metals, sulfur, nitrogen, etc.) are necessary some adaptations in the unit like a catalyst with higher resistance to metals and nitrogen and catalyst coolers furthermore, it’s necessary to apply materials with most noble metallurgy due to the higher temperatures reached in the catalyst regeneration step (due to the higher coke quantity deposited on the catalyst), that raises significantly the capital investment to the unit installation. Nitrogen is a strong contaminant to the FCC catalyst because they neutralize the acid sites of the catalyst which are responsible for the cracking reactions.  

When the residue has high contaminant content, is common the feed stream treatment in hydrotreating units to reduce the metals and heteroatoms concentration to protect the FCC catalyst. Typically, the average yield in fluid catalytic cracking units is 55% in volume in cracked naphtha and 30 % in LPG.

Usually, catalytic cracking units are optimized to aiming the production of fuels (mainly gasoline), however, some process units are optimized to maximize the light olefins production (propylene and ethylene). Process units dedicated to this purpose have his project and operational conditions significantly changed once the process severity is strongly raised in this case.

The reaction temperature reaches 600 oC and a higher catalyst circulation rate raises the gas production, which requires a scaling up of the gas separation section. Figure 7 presents a typical scheme for a gas separation section for a fluid catalytic cracking unit. 

Figure 7 – Basic Process Flow Diagram for a Typical Gas Separation Section from FCC Unit 

Over last decades, the fluid catalytic cracking technology was intensively studied aiming mainly the development of units capable of producing light olefins (Deep Catalytic Cracking) and to process heavier feedstocks. The main licensers for fluid catalytic cracking technology nowadays are the companies KBR, UOP, Stone & Webster, Axens, and, Lummus.

Despite the great operational flexibility which fluid catalytic cracking technology give for the refineries, some new projects have dismissed these units in the refining scheme, mainly when the new refinery objective is to maximize middle distillates products (Diesel and Kerosene) once this is not the focus of the fluid catalytic cracking unit. 

Synergy between Solvent Deasphalting, FCC and Delayed CokingUnits

           As aforementioned, the synergy between carbon rejection residue upgrading units can offer an attractive alternative to improve the bottom barrel conversion capacity to refiners. Figure 8 presents an example of refining configuration where is applied Solvent Deasphalting, FCC and Delayed Coking units, in this case the focus is maximize transportation fuels in the refining hardware.

Figure 8 – Refining Configuration Relying on Solvent Deasphalting and FCC Units

In the refining scheme presented in Figure 8, the deasphalted oil is fed to the FCC unit to produce LPG, naphtha, LCO, etc. while the asphaltic residue is applied to produce fuel oil and asphalt, in some refining configurations, the asphaltic residue can be fed to the delayed conking unit. For his turn, the delayed coking unit shares the vacuum residue as feedstock with the solvent deasphalting unit to produces intermediate streams that can be applied to produce light and middle distillates after the hydrotreating step, in some cases the heavy gasoil from the delayed coking units is fed to the FCC unit.

It’s fundamental to understand that in the current scenario, the combination of carbon rejection technologies, as a strategy to residue upgrading, as presented in Figure 8, is possible only to refiners with access to low sulfur crude oils, once the processes are unable to reduce drastically the sulfur content in the final derivatives, it’s necessary a great hydrotreating capacity to produce marketable crude oil derivatives. Despite this restriction, the synergy between FCC, Solvent Deasphalting, and Delayed Coking units offer relatively low capital and operating cost alternative to refiners in comparison with hydrogen addition bottom barrel upgrading alternatives as deep hydrotreating or hydrocracking units, refiners inserted in markets with high demand by transportation fuels demand can reach high yields of middle distillates (higher than 40 %) applying the refining configuration presented in Figure 8, a good result considering the relatively low capital investment when compared with Hydrocracking alternative. Refiners processing relatively low sulfur crudes (close to 0,5 % in mass) can apply the refining configuration similar to presented in Figure 8 to produce VLSFO (Very Low Sulfur Fuel Oil) in compliance with the IMO 2020 through the blending of atmospheric residue with middle distillates in a profitable manner.

Conclusion

           The synergy between refining technologies is a basic concept in the downstream sector and one of the first steps to define adequate refining configuration. The synergy between residue upgrading technologies is increasingly relevant to the refiners aiming to keep and improve the economic sustainability of the refiners, especially considering the downstream market after IMO 2020. To refiners processing low sulfur crude oils, the combination of carbon rejection technologies like Solvent Deasphalting, FCC, and Delayed Coking units can offer an attractive alternative to allow value addition to bottom barrel streams at the same time that minimizes the capital and operational capital costs.  

References:

MYERS, R.A. Handbook of Petroleum Refining Processes. 3a ed. McGraw-Hill, 2004.

SPEIGHT, J.G. Heavy and Extra-Heavy Oil Upgrading Technologies. 1st ed. Elsevier Press, 2013.

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

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

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