Figure 1: Artistic impression of the Refinery of the Future, where oil refining is fully integrated with a petrochemical facility and Renewable energy (ref ACS Catalysis)
During the past few years, we have seen a number of refineries shut down, convert to logistics terminals, or convert- partially/totally - to biofuels. These changes were market driven. Today we have the added parameter of the Covid-19 pandemic. We have seen that the lockdowns, due to the pandemic, have resulted in a decrease in transportation fuel demand but an increase in demand for petrochemicals. This has led to an increase in investment for Petrochemical projects including in crude oil-to-chemicals (COTC) facilities.
The demand for petrochemical products, which include everything from water pipes to nail polish, has drastically increased and it is predicted to keep growing due to the increased demand for plastics in developing countries along with the maturing demographics. Petrochemicals will account for more than a third of global oil demand growth by 2030 and nearly half through 2050, the International Energy Agency predicts. In order to meet future petrochemicals demand, naphtha yields in refineries will have to increase from current levels of 12% to 19% by 2040 – a growth driven by both rising demand and slower natural gas liquids supply growth. (IHS Markit).
The drop in demand for transportation fuels combined with other factors such as the growth of electric vehicles, has led to forecast that gasoline demand will continue to decrease, which will result in the unavailability of the "by-product" naphtha. Refineries will then have to be reconfigured to increase naphtha and other petrochemical feedstocks and products, and that can be done in two ways:
- New greenfield projects, designed with petrochemical yields +40%, such as the current COTC project recently built in Asia, which will be discussed later on.
- Brownfield investments in existing refineries, with technologies that enable increased petrochemicals production, either by retrofitting existing units, such as FCCs and hydrocrackers, or by using newer technologies being developed for repurposing existing refineries (IHS Markit)
There is no doubt, that today more than ever, refining companies are facing a more challenging and a more complex market environment. The growth of electric vehicles, as mentioned previously, together with the ongoing digital transformation being led by automation, analytics and artificial intelligence are all having a profound impact on downstream operations and market demands. Furthermore, as the world is slowly transitioning to a low-carbon economy, the demand for oil products is evolving and carbon emission cuts intensely increasing. In order to stay competitive against this backdrop, refineries must adopt low-carbon strategies. Using more sustainable feedstocks and disruptive decarbonising technologies will be fundamental to long-term profitability. However, companies will need to consider when to more fully embrace these opportunities while at the same time managing the changing risks.
Undoubtedly, the industry has a clear role in this energy transition. While decarbonisation can seem complex, several solutions are evolving, such as: Biofuels from waste, carbon capture utilisation and storage (CCUS), crude oil-to-chemicals (COTC) and hydrogen.
- Biofuels from waste
- Carbon Capture, Utilisation and Storage (CCUS)
- Crude oil-to-chemicals (COTC)
- Hydrogen
Following the threat of closure that some refineries are facing, some have opted for a different alternative: converting plants to produce biofuel by processing vegetable oil and waste oils. BP, TotalEnergies & Eni, have all outlined in recent months, plans to grow their biofuel capacities by two to five-fold by 2030 while reducing their global oil refining footprints. The very first conventional refinery in the world to be converted into a bio-refinery was the Venice bio-refinery owned by the Italian refiner ENI and this bio-refinery has been in operation since 2014. ENI is also home to Europe’s most innovative refinery, opened in 2019, Gela Bio Refinery’s plant can process vegetable oil, frying oil, fats, algae and waste by-products for the production of quality biofuel. A new plant (Biomass Treatment Unit), within the same bio refinery, was launched in March 2021 and aims to create a zero-kilometre circular economy model for the production of biodiesel, bio-naphtha, bio-LPG and bio-jet fuel.
ENI’s continuing development in the field of advanced fuels produced from waste will look to the possibility of obtaining pyrolysis oil from the treatment of end-of-life tyres (ELTs), and bio-oil from OFMSW (organic fraction of municipal solid waste), which can be used directly as a low-sulphur fuel for maritime transport or refined to obtain high-performance biofuels. (Eni)
Carbon capture technologies will enable refineries to make CO2 available for either storage (CCS) or use (CCU), integrating the sector into a circular economy. Maximization of chemicals production with integrated carbon capture and utilization can lead to major reduction in emissions.
There are three main approaches to carbon capture: pre-combustion capture, post-combustion capture and oxy-fuel combustion. The chosen technology depends on whether the facility is a new or retrofit plant. Other considerations include capital and operating costs.
Crude oil has conventionally been used to produce transportation fuels like gasoline, diesel, and other fuels. As petrochemical demand is expected to increase, refiners and downstream players are now looking to prioritise chemicals over fuel production. By targeting the integration of petrochemical production capability in one facility.
While most refineries convert ~ 5%–20% of crude into petrochemicals (Gulf Petrochemicals & Chemical association ), some existing refineries now have up to 45% of the output as chemicals, including olefins, aromatics, glycols, and polymers.
Figure 2: Refinery Integration Levels (Source: IHS)
The below listed three strategies are being predominantly used in COTC plants:
- Direct processing of crude oil in steam cracking:
The steam cracking technology has developed over time in order to process different feedstock i.e., naphtha, gas oil, and ethane. Using crude oil directly in the steam cracker to produce light olefins leads to the formation of coke and fouling of the crackers. However, some technologies have been developed recently, ExxonMobil for instance, has implemented a technology which preconditions the crude oil before using it directly in the steam cracker, to produce ethylene, propylene, and related products.
- Integrated hydro-processing/de-asphalting and steam cracking:
The hydro-processing/de-asphalting step produces highly paraffinic, de-asphalted and de-metalized stream, which can later be processed in the steam cracking unit.
- Processing of middle distillates and residues using hydrocracking technology:
This type of processing involves hydrocracking of diesel and products from the vacuum distillation unit to produce naphtha range stream, which can later be processed to produce aromatic compounds. [Future Bridge]
Most of the COTC plants/projects that have started operating or are planning to start operations are based in China and the Middle East. China’s new mega refineries can convert as much as half of their crude oil into petrochemicals (Economic Times), which is attracting global investors to the region. The plants based in China are more focused on the production of paraxylene, whereas Saudi Arabia’s project is more focused on Olefins.
Figure 2: Refinery Integration Levels (Source: IHS)
Aramco, partnered with Chevron Lummus Global (CLG) CB&I (now McDermott), plans to commercialize its thermal crude to chemicals process that aiming at converting 70-80% of crude oil to chemicals
Depending on the production process, hydrogen is classified as either grey, blue or green.
The cost of making ‘clean’ hydrogen is still relatively high and for it to be used, the price needs to drop substantially, and that could be achieved whether by finding places with cheap renewable energy, such as Chile and Saudi Arabia, or relying on improved technology. The blending of hydrogen into the existing natural gas pipeline network has the potential to help with the variable output from renewables. If implemented under appropriate conditions and at relatively low hydrogen concentrations (less than 5–15%), this strategy of storing and delivering energy may require only minor modifications to the operation and maintenance of the pipeline network. Ammonia is another alternative, where its cracking can reproduce hydrogen closer to the end-user.
It is safe to say that refiners have officially begun the long journey of “reinventing” their business; whether it is by using Biofuels from waste; CCUS; COTC (through key technology components such as resid hydrocracking, hydrocracking, hydrotreating, and steam/thermal cracking.) or, looking to Hydrogen as the fuel of the future.
COTC can surely help refiners to tackle the current market dynamics and remain profitable, however, it requires immense capital investment. Therefore, the refining industry is challenged by the unclear nature of its future. There remains uncertainty how the refining industry will adapt to these changing trends. How much capacity will be rationalized and how much of it will be repurposed? And how much will be integrated into petrochemicals?
Join us at ME-TECH 2022 – Middle East Technology Forum for Refining & Petrochemicals (14-16 February, Dubai) a where leading refining and petrochemical professionals will discuss and share their valuable knowledge on the very latest industry innovations, market trends, challenges and the continued importance of integration for competitive advantage. For more information, visit metech.europetro.com.
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