Cleaner fuels shift refineries to increased resid hydroprocessing

UPGRADING BOTTOMS-1

Lawrence Wisdom, Eric Peer, Pierre Bonnifay
IFP North America Inc.

The technology options to upgrade the bottom of the barrel have changed dramatically since refining began.

In early operations, unconverted crude was land-filled. As a result of high gasoline demand, thermal cracking was introduced. Then, hydroprocessing made inroads because of three major factors:

• The low cost of hydrogen from catalytic reforming
• Oil price hikes in the 1970s
• Environmental regulations.

In the future, refiners are expected to continue to rely on hydroprocessing to meet product quality specifications required by government regulations.

This first article of two examines how the refining industry has processed the bottom of the barrel over the years and where the industry is headed at the turn of the century. The second article will compare coking and hydroprocessing in a case study.

History

The first refinery in 1861 was nothing more than a cast-iron kettle, perhaps 7 ft in diameter, with a tight cover, set in a wood-burning firebox. Vapors from the top went through a coil of pipe immersed in running water in a wooden tank alongside the kettle.

Typically, the batch operation lasted 3 days. Everything but the kerosine was discarded, presumably in a landfill. The kerosine displaced whale oil, which was being sold as a premium for lamp oil.

It would take another 50 years before the first continuous pipe still would be introduced. It dramatically increased product quality and reduced production costs.

With the introduction of the automobile in 1893, the demand for gasoline grew rapidly. Scientists invented cracking technologies to increase the yield of gasoline per barrel of crude. Refineries developed thermal cracking in 1914 and delayed coking in 1930 (Standard Oil Co., Indiana).

The breakthrough development of catalytic reforming in 1940 led to a new, major, and inexpensive by-product-hydrogen. Low cost hydrogen provided the economic incentive for the rapid commercial development of hydrotreating in the 1950s, followed by hydro cracking in the 1960s. Key dates in the development of new technologies are shown in Table 1 [51,431 bytes].

North America refining growth

From 1860 to 1960, the refining industry grew in response to the increasing demand for gasoline based on the processing of light crude oil. Environmental regulations were very relaxed, and crude oil was very inexpensive by today's standards.

By 1960, there were 294 refineries in the U.S., with an average capacity of 35,000 b/d of crude oil. U.S. coking capacity was 318,000 b/d. However, in response to the increasing demand for gasoline, coking capacity grew to 902,000 b/d by 1971.

Hydrotreating capacity also grew to 1.9 million b/d as a result of the upgrading of naphtha to gasoline via catalytic reforming. With the increase in hydrogen availability as well as low-cost natural gas, hydroprocessing began a steady growth for the production of higher-quality transportation fuels. A comparison of the growth of coking and hydrotreating processes in North America is shown in Fig. 1 [87,209 bytes].

Residue hydroprocessing received additional attention in the 1980s with the passage of the U.S. National Environmental Policy Act in 1970, which was a direct response to the Santa Barbara Channel oil spill the year before. In 1971, Japan's MITI approved strict refinery sulfur emissions levels, and the Organization of Petroleum Exporting Countries hiked the price of crude oil.

In the coming decades, environmental laws will have a major impact on technology selection in the U.S. and in other regions of the world. Most of the refinery products will be treated in a hydroprocessing unit.

For the North American market, hydroprocessing grew from 1.9 million b/d in 1960 to 13.3 million b/d in 1996. With changes in oil prices and environmental laws, North American refineries shrunk from 294 refineries in 1960, with an average capacity of 35,000 b/d, to 163 refineries in 1996 with an average capacity of 95,000 b/d.

From 1980 to 1996, refineries in the U.S. added 600,000 b/d of residue hydroprocessing capacity and an equal amount of coking capacity. This change was a clear response to the oil price hikes in the 1970s and the enactment of new environmental laws, which took effect during this time.

Asia/Pacific refining

In Asia/Pacific, the disposal of coke is a major problem. This region does not have an outlet for high sulfur fuels as do North American refineries. As a consequence, residue hydroprocessing has become the leading process for upgrading the bottom of the barrel. In many of these refineries, residue hydroprocessing is added to produce low-sulfur fuel oil or to maximize gasoline production through integration with resid fluid catalytic cracking.

As shown in Fig. 2 [55,870 bytes], residue hydroprocessing, such as ARDS (atmospheric residue desulfurization), VRDS (vacuum residue desulfurization), and residue hydrocracking, continues to be the technology of choice for this market.

Europe refining

A third major refining market is Europe, which follows neither the trends of North American nor Asia/Pacific markets. Over the years, the European market has gravitated towards a refinery with a visbreaker and fluid catalytic cracker as its main processing units to make gasoline and medium-to-high-sulfur fuel oil.

With the declining demand of high-sulfur fuel oil due to new environmental regulations, refiners are looking at options to reduce fuel oil production or at least to lower its sulfur content.

As shown in Fig. 3 [53,652 bytes], the selection of coking and hydroprocessing is currently about the same for this market. However, as a percent of crude throughput, the level of European bottom of the barrel upgrading is lower than that of either the North American or Asia/Pacific markets.

Although there are good strategic reasons to add bottom of the barrel upgrading in many regions, the margins are not always high enough to justify the investment cost. However, 74,000 b/d of residue hydroprocessing capacity is currently under construction in Europe (Italy, Slovakia, and Poland).

Market trends

Worldwide economic growth, particularly in the developing regions of the world, is causing increased demand for distillate fuels. Diesel fuel is the dominant transportation fuel in many of the developing regions. In many countries, buses, trains and taxis are the principal means of transport, and these vehicles use diesel fuel. Middle distillate consumption in some developing regions of the world is expected to increase by approximately 5%/year through the year 2000.

Refiners that add crude-distillation capacity to increase their distillate-production rate will be faced with a surplus of residual fuel oil in a decreasing market for heavy fuel oil. This is shown in Fig. 4 [46,609 bytes], which also highlights the regional demand for heavy fuel oil as a percentage of total refined products.

The U.S. shows the smallest reduction in residual fuel oil demand as a result of the massive amount of conversion capacity added from 1960 to 1996. Asia and Latin America are now following this same pattern, and this trend should continue well into the 21st century.

The residual fuel oil remaining will be required to meet the environmental needs for the stationary land-based markets. High-sulfur fuel will continue to be sold to the marine bunker market as well as those power plants equipped with flue-gas desulfurization facilities.

Some refiners have added residue hydrocracking capacity to convert and desulfurize unconverted bottoms. This enables the refiner to meet new environmental specifications for the residual fuel while generating a by-product distillate (gasoline and diesel) to pay for the investment. Other refiners are opting to become more proactive in the power market by cogenerating electricity and hydrogen through the construction of combined-cycle gasification plants.

The result of these market trends should be an ever-widening price differential between high-quality transportation fuels and high-sulfur fuel oil. Price differentials approaching $10/bbl have historically provided significant incentives for refiners to increase the conversion of vacuum residua to meet the changing market demands. Fig. 5 [76,542 bytes] shows that the refining industry is on the verge of a new price upswing, which will give an economic boost to refiners with significant conversion capability.

The historical price differentials shown in Fig. 5 highlight the volatility in price differentials between diesel and high-sulfur fuel oil and between low and high-sulfur fuel oil. The differential between diesel and high-sulfur fuel oil is the driving force to add conversion capacity. The differential between low and high-sulfur fuel oil is the driving force to add hydrodesulfurization (HDS) capacity.

More and more refiners are now looking for a combination of desulfurization and conversion to meet their needs for the future. In a recent study completed by Chem Systems, price differentials are predicted to grow in the future as a result of current high utilization rates by refiners and steady growth in the Asia/Pacific market.

Technology options

Most planning departments will first evaluate their specific market for a given refinery, considering such factors as the forecast in demand and quality for transportation fuels, product prices, and the flexibility to process a wide range of crude oils.

In the 1960s and 1970s, many refiners selected the carbon rejection route for residue upgrading because it was a mature, low-cost technology. Delayed coking and visbreaking became the popular thermal cracking options for many refiners.

With the passage of the Clean Air Act and other environmental legislation in the U.S. and abroad, refiners began installing hydroprocessing technologies to clean up cracked stocks from the cokers and visbreakers. New cokers required extensive hydrotreating of all products, thus changing the economic picture for thermal cracking of the bottom of the barrel.

With the necessity to convert residue and to remove sulfur, refiners frequently turned toward residue hydroprocessing. In Asia/Pacific, where many new refineries have been constructed over the last 10 years, residue hydroprocessing has been the preferred choice (Fig. 2).

Two approaches have been very popular: (1) atmospheric residue desulfurization (ARDS) followed by resid fluid catalytic cracking (RFCC), which can maximize gasoline production, and (2) ebullated-bed hydroconversion (H-Oil) for upgrading vacuum residue in combination with fluid catalytic cracking (FCC) or gas-oil hydrocracking.

As shown in Fig. 6 [231,883 bytes], IFP has excellent technologies which serve both of these markets. The fixed-bed Hyvahl process is uniquely suited for upgrading atmospheric or low-to-moderate metals content vacuum residues for the production of low sulfur-fuel oil or as a feedstock to the RFCC unit. IFP recently started-up a new 25,000 b/d Hyvahl unit for Ssangyong in South Korea along with an IFP gas-oil hydrocracker and an R2R RFCC unit.

For processing moderate-to-high metal vacuum residues or low-metal residues requiring conversion, the H-Oil process, based on the ebullated-bed system, is the preferred choice. Ebullated-bed technology has the vast majority of the world's vacuum hydroprocessing capacity, and the H-Oil process boasts 75% of the ebullated-bed capacity in the world market.

Bibliography

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The Authors