M. W. DA SILVA, Petrobras, São José dos Campos, Brazil; G. HOEKSTRA, Hoekstra Trading, Chicago, Illinois; and T. MURPHY, Valuation Risk & Strategy LLC, Syracuse, New York
One of the biggest challenges to the crude oil refining industry over the past decades is the development of technologies capable of reducing the environmental impact of crude oil derivatives, while also raising their performance. Hydroprocessing technologies enable the production of cleaner and better performance derivatives, with higher yields of added-value products from bottom-of-the-barrel streams in the crude oil refinery.
The value addition to naphtha streams used to blend gasoline is especially difficult to determine in some cases, primarily due to the streams produced by deep-conversion processes like fluid catalytic cracking (FCC).
Despite the forecasted trend of declining demand for transportation fuels, many markets still depend heavily on these crude oil derivatives to sustain economic development. This is especially true in developing economies like Brazil and India. The production of high-quality gasoline from refinery naphtha streams is still fundamental to refiners aiming to meet market demand. In addition, considering the current specifications, the synergy between FCC and cracked naphtha hydrodesulfurization (HDS) is fundamental for refiners to reach profitable operations, primarily in markets with a high demand for transportation fuels.
Cracked naphtha is produced from refining processes like FCC that chemically crack low-value, heavy molecules into light fractions called naphthas suitable for use in blending gasoline. Compared to the FCC process, which has been in use for 70 yr, cracked naphtha HDS is a new process with only a 20-yr history of commercial use that has grown steadily since 2000 due to new ultra-low-sulfur (ULS) gasoline specifications (FIG. 1). Today, more than 200 cracked naphtha HDS units are in operation around the world, and new units continue to be built as clean gasoline mandates spread.
The North American market is an interesting case study that perfectly describes the challenges of producing ULS, high-performance gasoline. The U.S. Tier 3 gasoline specification is putting pressure on North American refiners by imposing a maximum sulfur content of 10 parts per million (ppm) in gasoline. This regulation causes difficulties for refiners to use their FCC naphtha—which may contain more than 2,000 ppm of sulfur—in the gasoline pool. Such extremely deep HDS (which removes more than 99% of the sulfur in cracked naphtha) causes side reactions in HDS units that greatly reduce the octane of the cracked naphtha and blended gasoline.1
The gasoline production process. Finished gasoline is blended from several different naphtha streams, as shown in FIG. 2. Each naphtha stream has advantages and disadvantages as a gasoline blend stock. Cracked naphtha from the FCC unit (FCCU) is one of the most valuable streams produced in the refinery because of its high volume and high octane—it comprises 40% of the volume of the U.S. gasoline pool and contributes more octane barrels than any other component. However, it is also responsible for 98% of sulfur in the gasoline pool. Therefore, when the sulfur content in finished gasoline is limited to 30 ppm or 10 ppm, the use of cracked naphtha without HDS is severely limited.
Today, the HDS of cracked naphtha enables refiners to adhere to sulfur limits in the final gasoline product. Faced with current and future gasoline sulfur specifications, the cracked naphtha HDS process is required for refiners with FCCUs to produce marketable gasoline consistently and economically. Moreover, an unplanned shutdown of this unit can quickly lead to a FCCU shutdown and, in extreme cases, the interruption of refinery operations.
Cracked naphtha HDS. HDS processes are described in literature.2 The HDS of cracked naphtha is challenging, since it is now necessary to remove 99% of sulfur components from this stream without saturating olefins, which are the components that give gasoline a high octane number.
Technology basics. In chemical engineering terms, HDS is called a “selective catalytic” process because it must selectively catalyze the chemical reaction of sulfur-containing molecules while simultaneously minimizing the reaction of high-octane olefins.
Today, the most used FCC naphtha hydrotreating process is Axens’ Prime G+ process (FIG. 3). This process exploits the fact that sulfur tends to concentrate in the heavier fractions of the FCC naphtha, while the olefins tend to concentrate in the lighter fraction; therefore, a fractionation step is carried out (the light gray distillation tower in FIG. 3) to remove the olefins-rich light naphtha before the heavier part of the FCC naphtha is exposed to deep HDS in the selective desulfurization step (the red-colored reactor in FIG. 3).
The cracked naphtha is fed to a diolefins reactor that promotes hydrogenation of diolefins. Next, the stream is separated into low-sulfur light fractions and higher-sulfur heavy fractions in a distillation tower. While the high-octane light naphtha is recovered in the top, the heavy fraction is removed from the bottom of the column and sent to a selective hydrotreating section to remove the bulk of the sulfur, with minimum olefin saturation and minimum octane loss. In this sequence, the hydrotreated naphtha is separated in a stabilizer column to remove light compounds, the bottom product is mixed with the light fraction, and the final product is directed to the refinery gasoline pool.
Other technologies that apply selective hydrotreating to reduce the sulfur content in cracked naphtha are ExxonMobil’s SCANfining process and Topsoe’s HyOctane process.
A special challenge: Dienes (diolefins) control. A key parameter in cracked naphtha HDS is the conjugated dienes content. These compounds are chemically unstable and tend to suffer oxidation reactions, leading to gum formation in the reactors of HDS units. In turn, this leads to a high pressure drop and short operation campaigns. The selective desulfurization processes described above usually use a low-temperature hydrogenation step (dark gray reactor in FIG. 3) as the first step to convert these dienes to more stable olefins.
Modern tools for optimization. Recently, refiners have been applying analytical methods, such as ASTM D6730 (detailed hydrocarbon analysis) and ASTM D5623 (sulfur speciation), to measure dienes, olefins and sulfur compounds in cat naphtha streams at the molecular level. These modern analytical methods, combined with process models, enable unit optimization and have recently been streamlined and automated for easy use in a refinery for better control and optimization of FCC naphtha HDS feed, distillation cut points and reactor operating conditions. This work is described in literature.1 For example, measuring olefins and sulfur compounds at the molecular level is essential for optimal control of naphtha fractionator cut points to maximize the capture of high-octane olefins in light naphtha, while simultaneously pushing the sulfur compounds down into the selective desulfurization reactor, resulting in less sulfur and less octane loss.
Cat feed hydrotreating. Another process option is to apply a cat feed hydrotreater (CFHT) upstream of the FCCU. FIG. 4 provides a simplified flowsheet to describe how the CFHT ties in with the FCCU and HDS unit. In this configuration, crude oil is distilled in the crude distillation unit (CDU), which includes a vacuum distillation unit (VDU). The naphtha exits at the top of the column and is processed in a naphtha hydrotreater (NHT) and a reformer to desulfurize it and increase its octane before it is then sent to the gasoline pool (G).
The next heavier cut (straight-run diesel) is desulfurized in a diesel hydrotreater (DHT) before it is then sent to the diesel pool (D).
The next heavier cut [vacuum gasoil (VGO)] is too heavy for use in road transportation fuels. To increase its value, it is chemically cracked in the FCCU for the primary purpose of producing more cracked naphtha for the gasoline pool.
With a CFHT unit, it is also possible to send cracked products from the delayed coker—which is another chemical cracking process—to the FCCU train. This can add sizable value by converting bottom-of-the-barrel vacuum residue (VR) molecules into FCCU feed and eventually into high-value gasoline.
The section of the refinery identified by the dashed box in FIG. 4 is the FCC train, which is the focus of the authors’ economic analysis.
ECONOMIC ANALYSIS OF INVESTMENT OPTIONS FOR TIER 3 GASOLINE
The authors considered the FCC train in a hypothetical refinery with a 55,000-bpd FCCU in a market that will adopt a new 30-ppm clean sulfur gasoline specification. The refinery’s current FCC naphtha, which has been suitable for use in gasoline, will be too high in sulfur for that market. In addition, there is a possibility that the 30-ppm sulfur specification will be tightened to 10 ppm in 7 yr.
Investment alternatives and contingent cases. The refinery has an existing FCCU and is considering three investment alternatives for its FCC train: red, yellow and green. These configurations are shown below:
The contingent case includes the 30-ppm sulfur mandate being tightened to 10 ppm in 6 yr; therefore, the two contingent cases to consider are:
Capital costs and benefits. The capital costs and benefits for the three investment alternatives and two contingent cases are detailed in TABLE 1.
Benefits depend on future contingencies. The benefits for years 1–6 (TABLE 1) will apply for all years if the sulfur mandate remains at 30 ppm. If the sulfur mandate is tightened to 10 ppm in year 7, then the benefits for years 7–20 will be lower (see the “Years 7–20” column in TABLE 1).
Explanation of benefits. In the case of the red investment route, the capital cost is $90 MM for the new HDS unit, which enables the refinery to produce 30-ppm sulfur gasoline, using the new cracked naphtha HDS. This is the minimum investment required for a continued operation supplying a market with a 30-ppm gasoline sulfur mandate. This is the base case, and it is assigned a benefit of zero.
In years 7–20, if the sulfur mandate is tightened to 10 ppm, there will be a $25 MM/yr penalty vs. the base case. This is because the HDS unit will be run at a higher severity beyond its intended design, causing high octane loss. The refinery could still produce 10-ppm sulfur gasoline, but the HDS unit will be overstressed and will saturate more olefins, with an octane penalty of $25 MM/yr.
In the case of the yellow investment, the capital cost is $300 MM for the new CFHT, which enables the production of 10-ppm sulfur gasoline without an HDS unit because the CFHT removes sulfur from the FCC feed. It also improves the FCC feed quality, which allows feeding lower-cost feedstock (for example, higher-sulfur feedstock) to the FCC train with the same clean product yields, providing an upgrade margin benefit of $30 MM/yr in years 1–6 vs. the base case.
In years 7–20, if the sulfur mandate is tightened to 10 ppm, the upgrade margin benefit decreases from $30 MM/yr to $10 MM/yr, since the 10-ppm gasoline sulfur mandate constrains flexibility to feed lower-cost feedstock (such as higher-sulfur feedstock) to the FCC train vs. the base case.
In the case of the green investment, the capital cost is $390 MM for a new CFHT and a new HDS unit, which provides a margin benefit of $50 MM/yr. The upgrade margin benefit is higher than the yellow case because the existence of the HDS unit increases the flexibility to feed feedstocks of even lower cost (e.g., coker products) to the FCC train while producing the same clean product yields and product sulfur. In addition, the HDS unit is designed to meet the 10-ppm sulfur mandate even in years 1–6, before 10 ppm is needed. This overdesign for years 1–6 enables operations at lower severity, providing an octane benefit of $6 MM/yr in years 1–6 vs. the base case. This adds a total benefit of $56 MM/yr in years 1–6 vs. the base case.
In years 7–20, if the sulfur mandate is tightened to 10 ppm, the HDS unit severity increases to meet the 10-ppm octane mandate, which will eliminate the $6 MM/yr octane benefit realized in years 1–6, thus reducing the total benefit to $50 MM/yr for years 7–20.
Present values. The present values of the three investment alternatives for a 20-yr time horizon with a discount rate of 10% are detailed in TABLE 2.
The red investment is a $90-MM compliance investment required to stay in business. If the sulfur mandate is tightened to 10 ppm, its present value decreases by $104 MM (from –$90 MM to –$194 MM) due to the large octane penalty that comes with making 10-ppm sulfur with a highly stressed HDS unit designed for 30-ppm sulfur—at this point, this refinery might choose to shut down.
For the yellow investment, the upgrade margin benefits bring the present value to $40 MM. If the sulfur mandate is tightened to 10 ppm, then the present value decreases by $40 MM (from $40 MM to $0) because the FCC train must run a more restricted feed slate when making 10-ppm sulfur gasoline in years 7–20, which reduces the upgrade margin in those years.
For the green investment alternative, the upgrade margin benefit and gasoline octane benefit bring the present value to $86 MM. If the sulfur mandate is tightened to 10 ppm, the present value decreases by $24 MM (from $86 MM to $62 MM) because the HDS unit no longer retains the $6 MM/yr gasoline octane benefit (vs. the red base case).
ANALYZING TIER 3 INVESTMENTS FROM A REAL OPTIONS PERSPECTIVE
Derivatives. Options, futures and other derivative securities are important elements of modern finance and can reduce risk when properly applied. As described in literature,3,4 derivatives are embedded in financial assets, and also in tangible and intangible properties, structured products, trading and hedging strategies, and contracts that have flexible terms and conditions. Real options occur naturally as flexibility and growth opportunities that can be exercised over time in an environment of uncertainty.
Insurance can be modeled as a put option having an exercise price equal to the face value of the policy. Any loss in value of the asset is covered by an increase in value of the put option. Reinsurance contracts (commonly known as excess-of-loss contracts) are combinations of long and short call option positions on layers of potential losses. Manufacturing companies often rely on the futures market to lock in raw material costs, and real options exist in the flexible operation of physical equipment.
An oil refinery with the flexibility to switch inputs and outputs has an embedded real option to switch when heating oil is in greater demand than gasoline. Flexibility increases the value of every asset under conditions of uncertainty. Long-term contracts contain option-like features, including volumetric swing components, when demand is uncertain. Contract prices can be tied to an index or a basket of commodities. The value of these derivatives is determined using complex quantitative models.
Model risk. Models are merely abstractions of reality and are imperfect. The assumptions behind these models often do not hold up in reality. In the financial industry, quantitative models are used to measure value and risk to help managers make better decisions. In every case, it is critical that management understand both the asset being modeled and the theory and assumptions behind the quantitative model. Assessing model risk is a key element in preventing upsets and providing litigation support.
Engineering students learn the laws of physics and chemistry in an idealized setting (in a vacuum) before adding in real-world imperfections (like an atmosphere or friction). This is how industry professionals move from the basics of Newton’s laws to chemical reactor kinetics, or heat and mass transfer. Models are imperfect representations of reality. This is especially true in social sciences, which depend on human behavior and not on scientific law. Unfortunately, this is often forgotten once an equation is applied—such as Black-Scholes 1973—to value an option, or a more complicated quantitative model in the case of a credit default swap (CDS) or a collateralized mortgage obligation (CMO).
Application to the Tier 3 investment decision. Real options involve uncertain payoffs that depend on future contingencies. This concept certainly applies to investment and optimization decisions in refining, and it can bring important insights to improve decisions, even when applied in a simple, qualitative way. For example, in the Tier 3 investment example, if the sulfur mandate stays at 30 ppm for the 20-yr life of the project, the capital investments and present values are as detailed in TABLE 3.
Here, the green investment has the highest present value and, on paper, would be the best alternative. However, for a capital-constrained company, the red alternative—a $90-MM compliance investment required to stay in business—might appear attractive, at least for the next 6 yr.
Looking beyond year 6, if the mandate is tightened to 10 ppm in year 7, the payoffs on the investments change (TABLE 4). The 10-ppm contingency makes the green alternative look relatively more attractive, as it provides sustainable operation over the 20-yr time horizon with a positive present value of $62 MM, even in years 7–20. Conversely, the red alternative suffers a lethal blow in this case because of the high-octane loss on the overstressed HDS unit when the 10-ppm mandate kicks in. Analysis of the contingent cases exposes the high risk of the minimum-compliance, stay-in-business strategy—the 10-ppm contingency might bankrupt the refinery.
The real-options perspective can help interpret this result. The 10-ppm contingency case reduces the green investment’s present value by only $24 MM (from $86 MM to $62 MM), while the red investment’s present value falls by $104 MM (from –$90 MM to –$194 MM). This is because the green investment provides a real option to keep octane loss low even if the 10-ppm contingency occurs, and this option has large tangible value. The green option is more robust and profitable because it can hold up to future outcomes that could hurt its profitability.
The real-options perspective brings critical insight by factoring in a known coming contingency in a simple, semi-quantitative analysis.
A good next step in this economic analysis would be to factor in contingencies on the upgrade values provided by the CFHT. Those upgrade values depend on highly volatile crude price differentials and product margins—therefore, the CFHT provides another real option for feed flexibility. It would be straightforward to extend this analysis to include contingency cases on the CFHT upgrade value and to factor this into the investment decision. An assessment of the variance of future crude and product prices could then be brought explicitly into the estimated benefits for each investment alternative.
Takeaways. Increased gasoline performance requirements and tighter gasoline sulfur specifications, such as the U.S. Tier 3 specification, have stimulated investment in selective cracked naphtha HDS units in refineries around the world. These HDS units remove 99% of the sulfur from FCC naphtha, which is the largest component in the U.S. gasoline pool and its largest source of octane barrels. This relatively new refining process has grown from near zero in 1999 to more than 200 commercial units today and will continue to grow as gasoline sulfur mandates are enacted around the world. It has become a fundamental process for consistent, profitable manufacturing of ULS gasoline.
A CFHT is often used instead of—or in combination with—a cracked naphtha HDS unit to deliver additional upgrade margins through increased yields of clean gasoline and diesel. The authors’ economic analysis indicates that investing in a CFHT and a cracked naphtha HDS unit is a more attractive investment than an investment in either unit alone for an FCC refinery that supplies gasoline. A key reason is that the CFHT-FCC-HDS configuration provides flexibility to produce more clean gasoline and diesel from lower-cost feedstocks and to adhere to stringent future specifications profitably. The Tier 3 case is a good example showing how the financial concept of real options brings insight that can inform decision-makers by showing the financial impacts of contingencies over the project’s life, either qualitatively or quantitatively. This approach will lead to better decisions, especially in an industry that has an uncertain regulatory environment, along with highly volatile input and output prices. HP
REFERENCES
MARCIO WAGNER DA SILVA is a Process Engineer and Stockpiling Manager at Petrobras. He has extensive experience in research, design and construction in the oil and gas industry, including developing and coordinating projects for operational improvements and debottlenecking bottom-barrel units. Dr. Silva earned a Bch degree in chemical engineering from the University of Maringa, Brazil, and a PhD in chemical engineering from the University of Campinas (UNICAMP), Brazil. In addition, he earned an MBA degree in project management from the Federal University of Rio de Janeiro, and in digital transformation at PUC/RS, and is certified in business from the Getúlio Vargas Foundation.
GEORGE HOEKSTRA is President of Hoekstra Trading LLC, which conducts multi-client research projects on topics with high profit impacts in the refining business, including pilot plant testing, field testing and market research. Hoekstra Trading is the only company that does multi-client independent catalyst testing programs on refining catalysts. Prior to founding Hoekstra Trading, he worked 35 yr for Amoco and bp in refinery process research and technology management. He earned a BS degree in chemical engineering from Purdue University, and an MBA degree from the University of Chicago.
THOMAS MURPHY is CEO of Valuation Risk & Strategy LLC, an interdisciplinary consulting firm established in 1995 to measure the value and assess the risk embedded in alternative technologies and chemical processes for energy and energy-intensive industries. Prior to this role, he was a research chemical engineer with the DuPont Company. An expert in derivatives and complex financial models, Dr. Murphy’s experience includes 11 yr of hands-on experience in chemical process engineering and production management. He earned a BS degree in chemical engineering (with distinction) from Clarkson University, a PhD in quantitative finance and a JD degree in technology management law at Syracuse University.