As recovery from the COVID-19 pandemic begins, so will a return to normal life.
As recovery from the COVID-19 pandemic begins, so will a return to normal life. However, fuel and petrochemical demand may never return to normal. Shelter-in-place orders have devastated global demand, and climate change policies are designed to maintain lower demand. In this ever-changing world, refiners must target profit improvements.
At the beginning of 2020, the refining industry anticipated a year of profitability, with projects anticipated to support refinery expansions, upgrades and new grassroot efforts. The global COVID-19 pandemic introduced an unseen assailant on the industry worldwide, with its effect on oil and gas production still reverberating throughout the refining community.
The pandemic shockwave
Even though global oil prices closed at previous-year averages of $51/bbl, 2020 remained a year of volatility spurred on by countries adopting climate change policies to limit carbon emissions, and by the growing global pandemic crisis. Starting in mid-2020, the refining industry desperately tried to reinvent itself as the pandemic destroyed fuel demand, exposing an unforeseen future reality of a world operating with a much lower hydrocarbon dependency. That reality portends a high probability that, in the coming years, hydrocarbon production could remain weak as recovery efforts from the pandemic begin to take hold.1
Therefore, to survive this volatility, the modern refinery must increase opportunities to remain profitable. Reducing lost profits from the refinery process and investing in more efficient technologies that improve profitability are of utmost urgency as the industry moves into post-virus stability.
Even before the events of 2020, a major topic of concern was the impending implementation of the International Maritime Organization’s (IMO’s) 2020 sulfur cap regulation, a marine fuel regulation mandating the reduction of sulfur content in marine fuels to a maximum of 0.5% and total ash content below 60 ppm. Although the IMO 2020 regulation was not fully enforceable because of the global pandemic, it has had an impact on refiners who are no longer working at peak capacity—and who are unable to make the investment in fuel oil and/or have been forced to close their facilities altogether.
During the post-pandemic shift, it is important that refiners evaluate key technologies to become more sustainable, target new market opportunities, and reduce operating costs to ensure that lost revenue can be obtained by the most efficient processes. The lack of refined product demand, coupled with refineries operating significantly below peak capacity, is delaying turnaround periods and postponing planned facility upgrade activities. Delaying these projects directly affects future profits and operating growth, particularly if key enabling technology improvements have been neglected because of the pandemic.1
The transition began before the pandemic
Saudi Arabia’s decision to cut oil production and postpone expansion projects into 2021 reflects expectations for demand to weaken further as business operations across the globe continue to be impacted by the pandemic crisis. Reducing waste and stabilizing profits from key refining assets are paramount and are the only actualities that can support growth in 2021.2
In addition to a buildup in primary distillation capacity, Asia-Pacific refiners invested heavily in catalytic cracking, hydrocracking and petrochemical production. It is apparent that the growth in petrochemicals and the utilization of refined products will support profitability in the post-pandemic Asia-Pacific market. National oil companies in China and India are revisiting plans to expand refining capacities from earlier mandates prior to the outbreak. Conversely, Japanese refiners appear to be heading into a second round of capacity reductions.3
Overall, the long-term transition from fuel to petrochemicals appears to be the right direction for the market to take to remain strong. The route for middle distillate conversion to chemicals with existing technologies is challenging, and technology improvements are required to support this transition. Long-term demand and uncertainty concerning middle distillates have added to this issue. This long-term drive for petrochemicals will increase the use of catalytic cracking, resulting in increased slurry production and lost revenue if not addressed by applying the right separation technologies.
Dynamic demand on the reactors
The first commercial fluidized catalytic cracker (FCC) was introduced 70 yr ago. To keep FCC technology evolving and current, a continuous string of mechanical and catalyst improvements have been implemented to respond to factors, such as the degradation in feedstocks and the need for product quality improvement, and to other factors, including petrochemical drivers and environmental pressures. In many cases, improved catalysts have led to innovation, such as the advent of zeolites, which has also led to the implementation of riser cracking. Catalyst advances have also led to improved selectivity to allow for more and heavier feed processing in a refinery. This selectivity and the reduced demand for fuel oil have led the way to the concept of increasing the amount of residual oil entering the FCC unit (FCCU).
Catalyst coolers incorporated into FCC regenerators and highly selective catalysts with the ability to give high conversion with reduced coke are examples of technology improvements that the refiner can use to dig deeper into the crude barrel. As refiners introduce larger quantities of residual into the FCCU, slurry oil yields increase, and the quality of the slurry oil decreases due to a larger proportion of asphaltenes and heteroatoms entering the FCCU. This is relevant because the level of asphaltenes in the slurry oil becomes a factor in deciding which technology is best for removing particulate solids. Asphaltenes are the most hydrogen-deficient constituents of slurry oil. They become more active and react with one another at higher temperatures—especially in the presence of metal surfaces—to form coke. To minimize downstream processing difficulties, the removal of the contained catalyst will keep solids diluted below recommended concentration levels.
The solution right under our reactors
Slurry oil yields differ from each FCCU operation. Complex refineries can reduce slurry generation to below 4% of the FCC yield for petrochemical production. As a transportation fuel, FCC can see yields as high as 12%. Regardless of the slurry make percentage, if it is not handled properly, the result is profit loss and waste that must be disposed of properly. Generally, refineries can mix slurry into heavy fuel oil as a viscosity cutter. However, slurry oil’s low API gravity limits how much can be blended.4
Clarified slurry oil (CSO) applications and markets
The use of slurry oil as cutter stock for heavy fuel oil blending has also historically been a major outlet for slurry oil. However, trace metals deposited on FCCU catalysts (e.g., nickel, vanadium and sodium) or adhering to catalyst particles and FCCU catalysts themselves—that contain aluminum and silicon as major components—can combine with other elements to form high-melting-point compounds that are corrosive to valve seats and exhaust valves in diesel engines. Solids contents for marine and refinery use in the range of 50 ppmw–150 ppmw are generally permissible.5
Beyond fuel use, CSO is also sold to make carbon black, which is used in automobile tires, belts, hoses and pigments, among others. The carbon black industry has always used slurry oil as feedstock, but this use is more prevalent in the Asia-Pacific region than in North America. Typical carbon black feedstock properties are provided in TABLE 1.
The global consumption of carbon black feedstock is approximately 130,000 bpd, with most of the market focused on the highly profitable low-ash specialty grades. The required density for carbon black feedstock is high, and special attention is needed to operate the FCCU fractionator at a high-enough temperature to obtain the desired density. Some refiners do not have the ability to obtain the required slurry oil density for carbon black applications. In addition, specialized separation equipment is required to meet the less than 50-ppm catalyst fines to obtain the greatest profits.
Some refiners increase slurry consumption to increase value in hydroprocessing unit process streams by feeding CSO to hydroprocessing, primarily hydrocracking or severe hydrotreating. Slurry oil solids contents should be reduced to very low levels to prevent operational disruption. Downflow packed-bed reactors will accumulate particulates near the entrance of the reactor, which will eventually bridge the hydroprocessing catalyst particles and cause plugging and premature shutdown. Reactors operating in trickle flow do not have the velocity to carry catalyst particles through the packed bed.3
Separating from the competition, but not from profits
Catalyst particles (ash) are a particular problem for slurry, especially for low-API and viscous oils needing long residence times to allow for catalyst settling. Obtaining low ash (< 0.05 wt%) requires special techniques such as heating, chemical additives, filters, electrostatic precipitators, centrifuges and cyclones. The selection of an attrition-resistant catalyst helps to a great extent, and a few refiners buy higher-priced hard catalysts to alleviate ash problems in slurry oil.5
Historically, holding tanks are used to allow solids to settle out of the slurry oil. Many refiners de-ash with chemical settling aids, which accelerates ash settling in storage. These chemicals are polymeric compounds that adhere to the catalyst surface, causing agglomeration of the fine particles to accelerate separation. In most countries, sludge from slurry oil holding tanks has been listed as a hazardous waste. Frequent and expensive cleaning of settling tanks is required. Depending on the tank size and rate of slurry oil production, cleaning costs can range from $1 MM–$4 MM per cleaning. In the absence of countermeasures, increasing residual feed to the FCCU tends to increase the rates of slurry oil production and sludge formation.5
The first membrane filters entered the slurry oil service market in 1990. One company’s filtersa operate at temperatures up to 315.56°C (600°F) and employ tubular porous metal elements. The solids collect on the inside of the elements, while the filtrate passes through to the outside. Another companyb uses porous sintered woven wire mesh metal filters and operates at 204.44°C–343.33°C (400°F–650°F). A third companyc employs 2-µm to 5-µm woven wire filter elements, recommends a light-cycle oil backwash at 176.67°C (350°F) and claims 85%–95% solids removal from the feed slurry. A fourth companyd uses sintered porous metal filters with solids capture inside the tubes. This company claims a product with < 50-ppmw solids, and, in a departure from its competitors, uses a gas-assisted (pressure-assisted) backwash for rapid filter element cleaning.3
Electrostatic precipitators are routinely used to remove catalyst fines from the FCCU stack, and a similar principle is used for the removal of solids from liquids in an electrostatic slurry separator. Electrostatic separation of FCCU catalyst fines from slurry oil has been in commercial operation for more than 30 yr. This technology has continuously been improved to offer a more robust, automatic process to remove catalyst fines from slurry oil or other hydrocarbon streams using dielectrophoresis. Only electrostatic separation can capture sub-micron catalyst fines. All other technologies are limited to the size of the particle captured (typically > 15 microns).3
Unique to electrostatic separation technology is the ability to backflush with raw feed or vacuum gasoil. This increases the middle distillate production and reduces loss from decreased reactor productivity. The technology is not affected by the presence of asphaltenes, making it an excellent choice for removing solids from residual FCCU-derived slurry oil and from gasoil crackers. Electrostatic separation operates efficiently and is impervious to plugging from asphaltenes and waxes, thus significantly reducing downtime and annual maintenance costs. The efficiency offered by electrostatic separation technology, coupled with reduced costs, has a direct and positive effect on a refinery’s bottom line and profit margins.
The economics of making the right choice
An example of the value generated by using electrostatic separation methods in removing FCCU catalyst fines from slurry oil is illustrated in the following example.
An 80,000-bpd gasoil FCCU has a slurry oil yield of 4 vol% (3,200 bpd). Catalyst content of the slurry oil is 2,000 ppm (FIG. 1). This is compared against the base case in which the refinery uses a holding tank to reduce its solids. The slurry oil holding tank is assumed to require cleaning once per year for 2,000-ppm slurry solids at a cost of $1.5 MM. Increased catalyst loads will incur higher-frequency slurry holding tank cleanings and additional total costs. A portion of the FCCU feed is used to backwash the electrostatic separator, after which it and the associated catalyst are fed back to the FCCU, thus reducing fresh FCCU catalyst costs. FCCU catalyst costs are assumed to range from $2,000/t–$5,000/t. It is estimated that the average product upgrade value for this CSO can be between $2/bbl and $4/bbl. Benefits from not having to purchase chemical settling aids were not considered, even though such costs are estimated to be approximately $45,000/yr. A basic case of slurry-to-bunker fuel specifications, with a minimal uplift of $2/bbl, is presented, along with one case for recovering 4,000 ppm of catalyst with $4/bbl uplift.
FIG. 1. View of 2,000-ppm main column bottom catalyst fines shown through a scanning electron microscope.
Profits from the use of an electrostatic separator range from $4.5 MM/yr–$11 MM/yr. Without the proper technology installed in this process, the reality is a true loss to the refiner.5
An electrostatic separator removes more than 99% of the catalyst from the slurry to provide a CSO product containing < 50 ppm of FCCU catalyst. Catalyst savings might not be as valuable for a residual unit, but would still be significant. Individual cases involving deep residual cracking benefits would have to be calculated based on a thorough knowledge of the residual FCCU feed, operating conditions and catalyst characteristics, among other criteria. It is important to note that smaller catalyst particles returned to the unit have an inherently larger surface-to-volume ratio, and could have a considerably higher residual cracking activity than the larger equilibrium catalyst held in the unit. With the increased focus on petrochemical production to increase profits, a major key to survival is finding the right technology to increase the value of slurry. An improved bottom line depends on achieving greater profit from the bottom of the barrel, even in a post-pandemic reality.3
The downstream industry must find new ways to return profits and maintain on-spec products. Whether it is providing highly valuable carbon black feedstock or meeting the new IMO 2020 mandate for marine fuels, the removal of FCCU slurry oil solids to low levels presents an opportunity for improved profitability for refiners. The ability to clarify slurry oil for use in higher-value applications—yielding more than $4/bbl or eliminating the need for the disposal of hazardous waste from a sludge in a holding tank—clearly supports the drive to stabilize and improve a refinery’s bottom line.
The upheaval brought about by recent events has opened the door to new opportunities for the industry to initiate changes to weather an uncertain future. Fossil fuels are an integral part of the global economy, and these fuels still contribute strongly to the world’s economies and to daily ways of life. The refining industry must continue to seek ways to innovate and evolve, and to meet the challenges in the years ahead. The first step is to invest in the right technology to increase refining capabilities and ensure a return to profitability in a post-pandemic reality. HP
b Pall Corp.
c Eaton Corp.
- Russo, R., “Pandemic hastens threat of closure for struggling oil refineries,” Hydrocarbon Processing, January 2021.
- Kelly, S. and D. K. Kumar, “A historic oil price collapse, with worries headed into 2021,” Reuters, December 29, 2020, online: https://www.reuters.com/article/us-global-oil-yearend-graphic/a-historic-oil-price-collapse-with-worries-headed-into-2021-idUSKBN2930FJ
- Scalco, V., “The plight of the modern refinery: Racing to meet IMO 2020 regulations,” Hydrocarbon Processing, December 2019.
- Methodology and Specifications Guide—Petroleum Product & Gas Liquids: U.S. Caribbean and Latin America, Platts, January 2012.
- Guercio, V. J., “U.S. producing, exporting more slurry oil,” Oil & Gas Journal, October 2010.
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