Special Report: Extraction route economical for benzene reduction, even for smaller US refiners

March 16, 2009
A recent study quantified the economic incentive for extraction vs. saturation to lower the amount of benzene in a typical US refinery gasoline product.

A recent study quantified the economic incentive for extraction vs. saturation to lower the amount of benzene in a typical US refinery gasoline product. Benzene saturation and extraction are two viable and proven routes available to refiners for complying with the pending benzene limits for US gasoline.

The study, conducted by Turner, Mason & Co., Dallas, found that, although the extraction route has many complexities compared with saturation, it is economical for many refiners, even smaller ones.

Creative solutions such as regional extraction facilities can overcome real and perceived hurdles allowing smaller refineries the opportunity to participate in the potential economic reward from producing chemical benzene.

Benzene processes

By January 2011, US regulations will require that most US refiners lower the benzene content of their gasoline to 0.62 vol %. The primary source of benzene in gasoline is from the reformer and, to a lesser extent, the FCC, and any naturally occurring benzene found in crude oil.

The FCC is a minor contributor to gasoline benzene, but it is difficult to remove benzene from FCC naphtha. Benzene from crude oil is generally directed to the light naphtha cut and represents a small volume of the gasoline pool for most refiners. Much of this benzene is already saturated in refinery isomerization units.

Refiners typically concentrate on removing benzene from the reformate stream. They have several strategies available to control the benzene content of reformate.

They can practice aggressive fractionation of the reformer feed to eliminate benzene precursors, but this may be an unreliable route to future compliance because about 1% benzene is produced in the reformer from feed that contains zero precursors.

Saturation of benzene to cyclohexane appears to be a favored route that provides a measure of control to the refiner unavailable from the precursor-removal approach. This is accomplished in common isomerization units and specialized versions of this process configured to handle higher concentrations of benzene typically found in light reformate. Many California refineries have successfully used this technology to produce low-benzene CARB gasoline since its introduction in the 1990s.

A third route is extraction of benzene from reformate for sale as a chemical. This proven technology is typically used in larger refineries or facilities owned by companies that participate in petrochemical markets in addition to producing fuels. We feel that refineries already extracting benzene will have the least difficulty complying with the looming 0.62 vol %/year benzene limit.

Saturation of benzene to cyclohexane is favored by most refiners not already extracting benzene. This technology provides a reliable method for controlling total benzene from reformate. Furthermore, it is a simple process with relatively low capital and operating cost.

Hydrogenation of benzene to cyclohexane requires about 4,500 std. cu ft of hydrogen and results in a volumetric gain of 20%/each barrel of contained benzene. The consumption of additional hydrogen could be an important factor for refineries with limited hydrogen supply.

Benzene and cyclohexane have about the same Reid vapor pressure; therefore, the effect on gasoline volatility is essentially neutral. The lower octane of cyclohexane relative to that of benzene, however, degrades the average octane of the gasoline pool.

Another route to compliance is to extract the benzene as a product with one of several extraction processes.

Benzene has always demanded a higher market price than its associated blending value in motor fuel; otherwise it would not have been produced. Extraction will, therefore, also be economically superior to saturation processes that further reduce the blending value of benzene, assuming a flood of new benzene does not disrupt current price relationships.

We believe, however, that real and perceived obstacles will discourage many refiners from choosing the extraction route. These obstacles include:

  • Increased regulatory burden of storing and handling benzene.
  • Economies of scale in the case of smaller refiners.
  • Relative access to chemicals markets.
  • A reluctance to enter new markets.
  • The additional overhead cost associated with a new business line.

Extraction vs. saturation

The starting point for our study was a typical 14,000-b/d refinery reformate stream that was split into light and heavy reformate cuts. We assumed the light reformate contained 20% of the benzene.

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Table 1 shows the major study assumptions. The resulting 2,800 b/d of light reformate was then processed in a saturation unit and alternatively in an extraction unit for comparison of these two options (Fig. 1).

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Because the benzene-rich light reformate stream is separated from the benzene-free heavy reformate in both cases, we chose to exclude the operating and capital cost of reformate splitting from our analysis. The loss of gasoline pool octane was restored by adding premium motor fuel to the gasoline pool in each case.

The cost of purchased hydrogen was charged to the saturation unit case. We assumed net operating costs of 25¢/bbl for the saturation case and 50¢/bbl for the extraction case. The saturation case’s economics also benefited from an increased volume of motor fuel from the volume gain of converting benzene to cyclohexane.

No depreciation or capital charge was included in the comparison because our intent was to determine the financial incentive for any incremental capital cost associated with the extraction route.

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With historic prices, the extraction and sale of benzene would have maximized the value of the light reformate stream relative to the saturation route. Results from our 10-year back cast (Fig. 2) demonstrate this point.

Additional net operating revenue/gallon of benzene recovered by extraction, compared to saturation, would have ranged from as little as 2¢/gal to as much as 48¢/gal during the past 10 years, under application of average quarterly prices. More importantly, there would have been no financially negative operating quarters (exclusive of any capital charges) during this period relative to the saturation route.

Back cast prices may not indicate future price relationships between benzene and motor fuels once permitted benzene levels are reduced. In fact, if every refinery implemented the extraction route, the resulting 32,000-b/d increase in benzene production would overwhelm current demand. We doubt this will occur, however, because so many refiners appear poised to take the saturation route.

Small refineries

As standalone entities, smaller refineries appear to be better served with the saturation option. For individual refineries, saturation’s lower capital cost is appealing. For small reformate streams similar to the volume in our study, it is doubtful the incremental benefit from extraction would provide an attractive return on the incremental investment needed for an individual refinery extraction unit.

Regulatory issues also multiply when dealing with streams that contain benzene greater than 20 vol %. Finally, marketing of a chemical product, such as benzene, may well be outside the expertise and business model of many gasoline-oriented refiners. Many refiners may therefore be inclined to choose the saturation approach.

Given the historic margins associated with recovering benzene, however, it appears refiners will continue to have some economic incentive to produce this chemical. Overcoming the aforementioned hurdles, therefore, becomes the primary task for those refiners not already producing benzene.

Larger refineries will have an easier time clearing these hurdles and can generally “go it alone,” if they choose. Smaller facilities will have much greater difficulty and creative solutions will be required for these refiners to participate in any future economic benefit from producing benzene.

One solution could be a joint venture of two or more refineries in which only one refinery processes all of the light reformate from multiple facilities. Partnering with another refiner that already operates an extraction unit would be an ideal solution for smaller plants.

This is especially the case if the existing extraction unit can be cost-effectively expanded. When this is not the case, a single, joint-venture facility could be constructed adjacent to one or more participating refineries.

A regional extraction unit is also suitable for a service-oriented third party to own and operate. This approach is similar to the many “across the fence” hydrogen plants located throughout the refining industry.

Such an entity could easily be structured as a master limited partnership, which could facilitate financing not readily available to individual refining companies in the current credit crunch. Furthermore, MLPs can typically accept lower returns on capital employed than their refining counterparts.

A centralized extraction facility can benefit its refinery “customers” in several ways in addition to allowing participation in margins associated with benzene recovery and sale.

Such a facility can:

  • Minimize overall capital spending by concentrating investment into a single, large extraction unit instead of multiple smaller saturation units.
  • Minimize capital spending at the refinery.
  • Avoid the extra hydrogen consumption associated with saturation (with the possibility of an increase in hydrogen supply from the reformer because precursor control would no longer be an issue).
  • Increase the octane of the refinery gasoline pool, which may offset the octane loss associated with producing ultralow-sulfur gasoline.
  • Allow the refinery staff to focus on what it does best, which is fuels production.
  • Allow for centralized marketing of a much larger benzene product stream.
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Table 2 shows that there are many refining centers in the US where a regional extraction facility would be a nice fit. Several of these refining centers also have reasonable access to ethylene producers willing to purchase the light raffinate by-product.

In locations where selling raffinate as a cracking stock is impractical, this material can still be blended into motor fuel with the use of higher-octane components such as ethanol. We believe a common extraction facility will likely be more attractive than individual saturation units, provided satisfactory agreements can be achieved among the participating refineries and, if present, the third-party operator.

The authors

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James W. Jones ([email protected]) is a senior vice-president with Turner, Mason & Co. He leads assignments that involve refinery process technology selection and design, independent engineer services, strategic capital investment studies, project management, and petroleum economics. Jones joined the firm in 1994 after 18 years with La Gloria Oil & Gas Co., where he held numerous positions at their Tyler, Tex., refinery, including 8 years as operations manager. He holds a BS (1976) in chemical engineering from the University of Texas and an MBA (1980) from the University of Texas, Tyler. Jones is a licensed professional engineer in Texas and is a member of AIChE.

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Donald L. Bird is a senior consultant with Turner, Mason & Co., Dallas. He joined the firm in 2008 following a 43-year career with Diamond Shamrock Refining & Marketing. In addition to his duties as vice-president of engineering for Diamond Shamrock, he also directed the operations of the company’s refinery in Three Rivers, Tex., and propylene fractionation and storage facility at Mont Belvieu, Tex. Before joining Turner Mason, Bird was an independent consultant specializing in turnaround management and refinery improvements. He holds a BS in chemical engineering from Texas A&M University.