Regeneration industry helps refiners control costs, limit liabilities

Catalyst dumped from reactors can go to regeneration, reclamation, or disposal facilities ( Fig. 1 [36,168 bytes]). Photo courtesy of Federal Container Corp.

About this report...
THIS YEAR'S CATALYST report deals with a variety of options, issues, and tasks that refiners face in their catalyst programs. Covered are spent catalyst regeneration, catalyst-selection processes, dense loading vs. sock loading, and new environmental regulations.

• CRI's optiCAT Plus pretreater requires catalyst to flow directly from the pretreater to the moving belt. Thus, in the summer of 1997, CRI had to cut a hole in the existing roof to mount the pretreater (Fig. 4). Photo courtesy of CRI. [29,605 bytes]

Together, the catalyst regeneration and metal reclamation industries help refiners control costs and limit future liabilities in the face of increasing regulation.

As refiners attempt to lower costs and comply with low-sulfur and hazardous waste regulations, they have increasingly relied on these facilities to manage their catalysts.

This article is the first in a series of two, and it covers the catalyst regeneration industry. The second article will review the major players in the metal reclamation and disposal industries.

Lower sulfur regulations have spurred the construction of new hydroprocessing units. Each barrel of hydroprocessing capacity adds new catalyst demand to the market. About 90% of the world's regenerated catalysts, according to Soren Marklund, president of Eurecat U.S. Inc., are hydroprocessing catalysts.

Regulations deterring catalysts from entering landfills have redirected spent-catalyst traffic from disposal options to regenerating and reclamation plants. In many cases, the potential liability associated with landfills provides enough justification to regenerate as much catalyst as possible.

Refiners have three options to deal with spent catalysts: regeneration, reclamation, or disposal (Fig. 1). By reusing their catalysts, refiners reduce catalyst costs as well as waste-often, however, at the expense of a shorter catalyst life.

Catalysts that have been deactivated by sulfur, coke, or carbon formation (for example, hydrotreating catalysts, hydrocracking catalyst, molecular sieves, precious metals reforming catalyst, petrochemical catalysts, and alumina) can be regenerated and reused. Regeneration can reduce both carbon levels and sulfur levels in spent catalyst to below 1% and can recover about 95% of the available surface area and catalyst lengths.¹

Spent catalysts that have aged or have been poisoned (feed contamination by lead, arsenic, silicon, sodium, nickel, or vanadium) sometimes can be regenerated. Usually, these poisons cause permanent inactivity that results in metals reclamation or disposal.

To present an accurate picture of the regeneration, reclamation, and disposal industries, major players are mentioned in this article. The refiner, however, should carefully conduct its own review of catalyst service companies to determine their suitability to its needs.

Waste designation

The most recent regulation to impact the U.S. spent catalyst industry is the U.S. Environmental Protection Agency (EPA) K-171/K-172 hazardous waste ruling (see accompanying article, p. 62. In June 1998, the EPA added spent hydrotreating catalyst and spent hydrorefining catalyst to its hazardous waste list (OGJ, July 13, 1998, p. 35). This regulation will be effective Feb. 8, 1999.

Before this ruling, spent catalysts were considered hazardous wastes only if they exhibited certain hazardous characteristics under EPA's toxic characteristic leaching procedure (TCLP) or if they were self-heating or pyrophoric.

Although the new rules will not affect the processes associated with catalyst regeneration and metals reclamation, they may affect the way these service companies store, handle, and dispose of catalyst. Hazardous wastes may be stored and transported in approved containers only. Resource Conservation and Recovery Act (RCRA) approved on-site bulk pads and U.S. Department of Transportation (DOT) approved containers are acceptable.

Although the regulation increases transportation and handling costs to both refiners and service providers, they will probably bring more business to regeneration and reclamation companies by limiting landfill activities.

As a hazardous waste, spent catalysts must undergo certain incineration and stabilization treatments before landfill. The EPA is in the process of creating these standards.

The Eurecat Pasadena, Tex., regeneration plant, which is currently obtaining a broad RCRA Part B permit to store hazardous waste, is optimistic about the regulations.

"The good thing about the regulation is that it provides more regulatory oversight and in turn assures refiners that the hazardous waste is managed correctly," says Marklund. "It is good for the credibility of our whole regeneration industry."

Risks and costs for regenerators increase when the product has to be moved from one country to another. Most regeneration services have facilities close to refining centers to minimize these costs.

With the reclassification of spent catalysts as hazardous waste, there will be increased state and federal scrutiny of waste management of spent catalysts. Several regulations govern the shipment of catalysts among countries:²

1. U.S. EPA 40 CFR Part 262, Subparts E and H regulates the export of hazardous wastes from the U.S.
2. The Organization of Economic Cooperation and Development (OECD) Council Decision on the Control of Transfrontier Movements of Waste Destined for Recovery Operations (March 1992) governs shipments to OECD nations.
3. The Basel Convention on the Control of Transboundary Movements of Hazardous Wastes and Their Disposal (May 5, 1992) may impact catalyst shipped for reclamation.
4. European Union regulations, protocols to the Basel Convention, or other bilateral/multilateral conventions may govern shipments.
5. National and state laws may govern certain catalyst shipments.

Low-sulfur regulations

As well as hazardous waste-designation regulations, low-sulfur regulations are also boosting the regeneration and metals reclamation industries.

The American Petroleum Institute (API) and the National Petrochemical & Refiners Association (NPRA) presented its updated gasoline sulfur plan to the EPA in July. The two organizations proposed a year-round average sulfur gasoline level of 150 ppm and a maximum per-gallon level of 300 ppm for 22 states (plus East Texas and the District of Columbia), which have large areas that do not need expensive reformulated gasoline (RFG). The current average is 340 ppm, and the current maximum is 1,000 ppm (OGJ, July 20, 1998, p. 34).

For nonattainment areas in the U.S., the 1998 Phase 1 complex model limits RFG-sulfur content to 500 ppm. The mandatory reduction in NOx required by the Phase 2 complex-model RFG to be implemented in 2000 may reduce sulfur levels to 100-150 ppm levels (OGJ, Jan. 5, 1998, p. 22).

The European Union will require gasoline to be no more than 150 ppm and 50 ppm in 2000 and 2005, respectively. Diesel requirements will be 330 ppm and 50 ppm for 2000 and 2005, respectively (OGJ, July 6, 1998, p. 4).

Since 1995, U.S. hydroprocessing capacity has increased by about 300,000 b/d. Worldwide, the capacities of hydroprocessing have increased by more than 3.7 million b/d (OGJ, Dec. 22, 1997, p. 41; OGJ, Dec. 19, 1994, p. 53).

The increasing numbers of hydroprocessing units require catalysts. The increase in catalyst has been a boon for both catalyst suppliers and catalyst regeneration services.

Francis Valeri, president of Eurecat SA, France, estimates that the volume of catalyst regenerated worldwide is about 40 million lb/year, 90% of which is hydroprocessing catalyst, the majority of which is from hydrotreating units.

According to Gary Stephens, general manager for Tricat Inc., higher-severity operation of these units has reduced cycle times, which has resulted in more-frequent regenerations. More-frequent regenerations, in turn, increase the volume of catalyst directed to regeneration and reclamation facilities.

Ex situ regeneration

Ex situ catalyst regeneration was introduced in the mid-1970s. During the 1980s, there was a rapid growth of ex situ regeneration services. Today, the industry's worldwide growth is slower but steady.

Stephen Blashka, technical services manager at CRI International Inc., estimates an annual growth rate of 5% in North America and Western Europe, and a rate of 10% in the Asia/Pacific region.

According to Blashka, the Asian crisis is having a positive effect on the regeneration industry. Although the crisis has slowed additional capacity, it has encouraged regeneration as Asian operators look to lower catalyst costs.

In the 1970s, most operators regenerated their catalyst in situ. Today, 90-95% of the catalyst regenerated in the U.S. and in Europe is regenerated ex situ. Most new hydrotreating units built after 1996 do not have facilities for in situ regeneration. In situ regeneration requires air supply and contact facilities to burn the coke from the spent catalyst and scrubber facilities to properly reduce the SO2 emissions.

Ex situ regeneration has several advantages over in situ regeneration. First, ex situ regeneration allows for close control of regeneration temperatures. Often, the in situ regeneration in the past was done in fixed-catalyst beds. This method was prone to temperature excursions and gas channeling. Temperature excursions lead to irreversible catalyst activity losses, and channeling led to incomplete regeneration.¹ Second, ex situ regeneration can reduce unit downtimes because in situ regeneration is longer and more difficult to control.

Third, ex situ regeneration allows for the analysis of the catalyst condition. It provides a better evaluation of the catalyst's reusability and activity recovery and a chance to remove catalyst fines and chips that contribute to pressure drop problems.

Finally, ex situ regeneration of hydrotreating catalysts allows for improved activity recovery because of the reasons stated above. In situ regeneration recovered only 50-60% of the catalyst activity vs. ex situ regeneration's 75-95%.

In situ-regenerated catalysts from reforming units often have better activities than in situ regenerated hydrotreating catalysts because reforming contamination is mostly carbon, not sulfur.³

It should be noted that a substantial sub industry exists to remove catalyst from the reactors. This inert-entry step before ex situ regeneration is not covered in this article (OGJ, Mar. 18, 1996, p. 64).

History of ex situ regeneration

In 1974, P. Ken Maher and several partners founded the first ex situ regeneration company, in Baltimore.

Their first facility, called CRI, began operations in Lafayette, La., in September 1976.

In 1980, CRI's second plant was built in Rodange, Luxembourg, to serve the European market. Since 1981, CRI has participated in a joint venture in a regeneration plant in Miyako, Japan, to serve the Pacific rim markets.

In 1982, CRI added a fourth plant in Medicine Hat, Alta. Shell Chemical Co. purchased CRI in 1989. In 1995, CRI added a new plant in Singapore.

In 1980, George Berebi started a competing regeneration company called Eurecat SA in La Voulte, France. Berebi later built a plant in Pasadena, Tex. Today, Eurecat also has operations in Jubail Industrial City, Saudi Arabia, and Niihama, Japan.

Akzo Nobel and ISIS (IFP) have owned Eurecat since 1995.

In 1992, Maher and other investors founded Tricat Inc. Tricat's first plant was built in McAlester, Okla., in 1993. In 1997, Tricat built a second regeneration plant in Bitterfield, Germany.

The first North American companies to use ex situ regeneration were Union Oil Co. of California (Unocal), Chevron Corp., and Atlantic Richfield Co. (ARCO) in 1976 and 1977. In Europe, Esso AG was the first company to use ex situ regeneration in 1978. Today, most refiners regenerate some catalysts.

Regeneration market

Although there are only three major players in the regeneration industry, the companies compete furiously. Worldwide, Eurecat and CRI together service about 85% of the world's spent catalyst; the remaining is serviced by Tricat Inc. and other companies.

Engelhard has regenerating facilities in Salt Lake City, Utah. The company has indicated, however, that it will not accept hazardous wastes.⁴

Blashka estimates that 60% of CRI's regenerated catalysts are from hydrotreating units, 15% from hydro-cracking units, and 25% from specialty applications, which include reforming and petrochemical operations.

Reforming catalysts are typically regenerated in situ because they have little or no sulfur and thus would have negligible emissions during regeneration.¹ When dumped, however, reforming catalyst is often regenerated ex situ and requires special care because of valuable metals such as platinum, palladium, and/or rhenium that it contains.

The three major regeneration companies use service and technologies to differentiate themselves from one another.

Technologies

As soon as the spent catalyst is removed from the operating unit, often with inert entry techniques, refiners send it to one of several catalyst-regeneration services.

Spent catalyst is screened to remove support and catalyst fines before entering the regenerator. Support can be washed, reclassified, and reused. Fines are typically sent to metals reclamation.

Because most metals reclaimers do not require carbon removal, fines are not typically processed in the regenerator. For precious metals catalyst fines, however, reclaimers impose a surcharge for catalyst with greater than 5% carbon. Thus, most companies regenerate precious metals catalyst fines.

If the spent catalyst is contaminated with hydrocarbons, the companies use a stripper prior to regeneration. Stripping usually occurs at 175-205° C.⁵ During regeneration, the carbon and sulfur levels are each reduced to less than 1%. Although regeneration can recover 75-95% of the catalyst's original activity, the fouling rate is often increased and thus, the catalyst may only last 50-90% of the life of its fresh state.

Eurecat, CRI, and Tricat each employs different regeneration processes. Eurecat uses a rotating vessel to achieve a slow burning of the catalysts. CRI uses a fluidized bed combined with a moving belt, and Tricat uses a fluidized bed.

Eurecat uses roto-louvre ovens for its regeneration plants (Fig. 2). The ovens both remove free hydrocarbons from the catalysts and regenerate the catalysts. A thin layer of spent catalyst is gently mixed with preheated air in a continuously rotating oven to achieve homogenous regeneration under close temperature control. The regeneration reaction is controlled by several parameters, which include catalyst flow rate, process air temperature, air flow rate, and continuous quality analyses.

In CRI's moving-belt regeneration process, the catalyst, spread in a thin layer on a porous stainless-steel belt, moves through a series of distinct heat zones to maintain a smooth temperature gradient (Fig. 3 [37,311 bytes]). CRI claims that its moving belt minimizes catalyst attrition and provides a gentle heat soak for the slow removal of carbon from deep within the catalyst pores.

CRI controls the temperature in each regeneration zone by adjusting several variables, which include bed thickness, belt speed, and sweep air. The catalyst is cooled and screened before being packaged.

CRI's latest advance is its optiCAT Plus process, which combines a fluidized bed pretreater with the conventional moving belt (Fig. 4). The pretreater efficiently strips hydrocarbons from oil-wet catalyst, while also removing the most reactive sulfur compounds. According to Blashka, improvements in hydrocarbon stripping have resulted in increased regeneration capacity and greater recovery of catalytic activity.

Tricat's regeneration process is called the Tricat regeneration process (TRP). TRP uses an ebullated bed to regenerate the catalyst (Fig. 5 [33,582 bytes]).

Screened catalyst enters two ebullated bed reactors. Air is used to fluidize the catalyst. The temperature is maintained at 850-950° F. by adjusting the catalyst feed rate, air temperature, water-filled cooling coils, and regenerator catalyst level.

Regenerated catalyst passes through a water-jacketed cooler before product screening and packaging. The flue gas from the regenerator is cooled before going to a dust removal step. Finally, the flue gas goes to the flue-gas scrubber to be scrubbed of SOx.

All three major players provide presulfurizing services after regeneration. For refiners, presulfurizing and in situ activation eliminate the need for in situ sulfiding. Many refiners choose presulfurized catalyst to help ensure thorough sulfiding of the catalysts. Presulfurized catalysts simplify unit start-up, reduce start-up times, and avoid the handling of sulfur-containing agents.

In 1998, Eurecat, CRI, and Tricat have introduced or plan to introduce presulfided catalysts. These catalysts require no in situ activation step.

Refiners' alternatives

The decision to regenerate is ultimately left to the refiner. The refiner makes a decision based on guaranteed regeneration results presented by the regeneration company: regenerated catalyst activity, the physical quality of the catalyst, and the regenerated-product yield.

The regeneration-services company tests various samples of the spent catalyst before whole shipment from the refiner. Physical parameters such as loss on ignition, solids content, carbon content, sulfur content, surface area, free hydrocarbon content, crush strength, and length distribution (for extrudates) are made. Companies also perform metals analyses for arsenic, iron, silicon, sodium, and vanadium. These data are provided to the refiner with a guaranteed regenerated-catalyst specification.

After a refiner's shipment arrives at the regeneration site, the service company samples the catalyst to ensure that there are no surprises during regeneration.

The surface area of the catalyst is a major determinant of its relative activity. The surface areas of the commercially regenerated product, a fresh sample of the catalyst, and the original spent catalyst are compared.

The most critical physical properties of the regenerated catalyst are the length-to-diameter ratio (L/D) and the fines content of the regenerated product. These properties affect flow distribution and pressure drops during the run.¹

Eurecat has bench-scale pilot plant test units in La Voulte, France, which allow it to evaluate catalyst activity following regeneration. The units operate over a range of conditions to simulate operating conditions.

CRI has a conventional pilot plant in its R&D center in The Woodlands, Tex., that allows it to place the catalyst in simulated operating conditions to evaluate the catalyst performance for resale or reuse. CRI is also currently constructing pilot plant units in its new R&D centers in Germany and Singapore.

Refiners have broadly six options:

1. Reuse the catalyst in the same unit.
2. Reuse the catalyst in a different unit in the same refinery.
3. Reuse the catalyst within its company.
4. Sell the catalyst to a third party on consignment, typically in collaboration with the regenerator.
5. Sell the catalyst outright to a regenerator.
6. Send the catalyst to be reclaimed and/or landfilled.

Historically, catalysts had very short life spans. In Europe, hydrotreating catalysts are usually recycled two or more times. In North America, hydrotreating catalysts are usually recycled only once. With the present regulations, U.S. refiners will likely regenerate hydrotreating catalysts more often in the future.

Hydrocracking, reforming, and selective hydrogenation catalyst are often recycled two or more times. As a general rule, after the catalyst can no longer be regenerated to at least 75% of its original activity, it is reclaimed or disposed of.

When the refiner decides to use the catalyst within the same refinery or within its refining network, it often chooses to cascade the catalyst to a less-severe service, cascade to a high-metals service, cascade to a high-silicon service, or cascade as make-up catalyst.¹

In cascading to a less-severe service, refiners use the regenerated catalysts in less and less demanding operations. For example, the catalyst may have originally come from a gas-oil pretreater. After its first regeneration, the catalyst may be placed in a distillate unit, which has less sulfur and less metals. Finally, the catalyst may be used in a naphtha unit.

In cascading to a high metals service, the regenerated catalyst may be placed in a guard reactor or the first reactor of a series. In this cascading alternative, the regenerated catalyst acts as a metals trap for downstream catalysts.

Refiners may choose to cascade to a high-silicon service. Silicon contamination deactivates the catalyst by carbon deposition. Refiners often choose regenerated catalysts in this service rather than a fresh catalyst because the fresh catalyst would not be fully utilized.

Finally, some units require frequent reactor skims to remove catalyst layers causing high pressure drops. Many refiners replace this skimmed catalyst with regenerated catalyst.

For refiners who choose not to reuse their regenerated catalysts, whether because of unit severity or a preference for fresh catalyst, most regeneration companies offer a resale business. The catalyst-regeneration company stays in contact with the catalyst needs of various operating companies in the world. The regeneration company stores the catalyst for the original owner until it finds a customer for the regenerated catalyst. At that time, the operator and catalyst-regeneration company share the profits (consignment) of the business exchange.

As another alternative, some companies purchase the spent catalyst outright and attempt to resell it. If a buyer cannot be found, the company will send it to reclamation services. Although refiners may lose the opportunity to sell the catalyst for a slightly higher price, this option is attractive because it limits the risks to the refiner.

Regeneration economics

As a rule of thumb, the incentive for refiners to regenerate is obtaining 75-95% of the their original catalyst's activity after regeneration for about 20% of the cost of new catalyst. Hydrotreating regeneration typically costs 50-60¢/lb. Fresh catalyst costs about $3/lb.

The refiner should do an economic analysis and weigh the costs and benefits of regeneration, reclamation, or diposal vs. the costs and benefits of new catalysts. The lost margin of a unit downtime can be as much as $100,000/day. Thus, fresh catalyst may be justified to maximize the run length and product yield of the unit. In certain cases, where landfill of hazardous wastes is permitted, landfill may be the best catalyst-management solution.

As a result of cost cutting, more operating companies consider their catalysts as assets rather than dispensable goods. This attitude among operators has increased awareness of the quality of catalysts, and has thus increased the standard to which refiners expect their catalysts to be regenerated.

As a result of higher quality demands from refiners and implementation of quality standards, Eurecat claims that its costs to regenerate have increased since the 1980s. Competition, however, has kept the price to refiners steady.

References

1. Neuman, Daniel J., "Novel Ebullated Bed Catalyst Regeneration Technology Improves Regenerated Catalyst Quality," presented at the 1995 NPRA Annual Meeting, San Francisco, Mar. 19-21, 1995.
2. "Exporting Spent Catalyst, Economical Solution or Regulatory Morass?" Cat Tales, Publication of Gulf Chemical & Metallurgical Corp., Summer 1998, p. 1.
3. Barry, James J., "Recovery and Disposal of Spent Catalyst," Oil & Gas Journal International Catalyst Conference, Houston, Feb. 2, 1996.
4. "Background Document for Capacity Analysis for Land Disposal Restrictions: Newly Identified Petroleum Refining Wastes (Final Rule)," U.S. Environmental Protection Agency, Office of Solid Waste, Washington D.C., June 1998, pp. -15.
5. Clifford, Roger K., "Spent Catalyst Management," Petroleum Technology Quarterly, Spring 1997, pp. 33-39.

Copyright 1998 Oil & Gas Journal. All Rights Reserved.