Refining Review-convertido.docx

Refining Review—A Look Behind the Fence

One end product of production activity is crude oil. Produced crude gains significantly in value once it is converted into finished products. Like upstream activities, refining involves operation at extreme conditions and application of advanced technology.

David Allan Consultant Houston, Texas, USA Paul E. Davis Chevron Richmond, California, USA

Drilling and production are only the beginning— complex refining processes, often conducted at extreme temperatures and pressures, are required to turn produced crude oil into the products that power a global society. From multibillion-dollar deepwater platforms to draglines scooping oil sands from permafrost, oil

producers hold the attention of the public. The crude oil from this effort disappears behind refinery fences at some 658 locations worldwide. These plants range from a Venezuelan facility running 149,000 m3/d [940,000 bbl/d] to locations running less than 160 m3/d [1,000 bbl/d].1 Despite the huge disparity in size, these

For help in preparation of this article, thanks to Dr. Douglas Harrison, Louisiana State University, Baton Rouge, USA.

Biofuels Other Recoverable resources

Natural gas liquids

120

Oil sands

Oil equivalent, million bbl/d

100 80

Crude and condensate

Oil sands, 651 billion bbl

Liquids demand

Heavy oil, 434 billion bbl

60 40

Conventional oil, 952 billion bbl

20 0 1980

1990

2000

2010

2020

2030

Year

>Global liquids supply and demand. Global liquids demand (transportation, industrial, residential, commercial and power generation) is expected to rise from the current 13.5 million m3/d [85 million bbl/d] to about 18.3 million m3/d [115 million bbl/d] in 2030 (left). Most of this demand will be satisfied by crude and condensate. As conventional crude reserves become scarce, increasing reliance will be placed on heavy oil to meet liquids demand. Recoverable heavy oil (22°API or less) (right) is nearly 50% of conventional oil reserves. Contributions from oil sands will grow throughout this period, increasing from about 320,000 m3/d [2 million bbl/d] to nearly 1.1 million m3/d [7 million bbl/d] in 2030. (Global liquids demand adapted with permission from ExxonMobil’s Energy Outlook, 2006, reference 2. Recoverable resources adapted from Meyer and Attanasi, reference 2.)

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refineries share a common goal of converting crude oil into valuable and usable finished products. That makes the refining story an important one—economically and technologically. It is also a story of scientific achievement and continuous improvement. Refining is a vital link in the world economy. Rising income levels and growing populations exert continuous pressure on transportation fuels and all chemical products made from oil (previous page).2 This pressure to produce a growing supply of fuels and chemicals coincides with increasingly stringent worldwide environmental standards. To meet these demands, refiners are literally digging deeper into the bottom of each barrel and processing more heavy oils as conventional crude supplies become scarce. This article discusses refining and its evolution from simple beginnings using batch equipment to today’s highly automated plants operating around the clock. We will also examine the growing presence of heavy oils in refinery feedstocks and the trend toward achieving nearly zero contaminant levels in transportation fuels.

Summer 2007

From Simple Beginnings to a Key Global Industry Although historians have noted the use of petroleum and tar in ancient times, the first reported refinery was built in 1860 in Titusville, Pennsylvania, USA, at a cost of $15,000. 3 Then, as now, the refiner’s challenge was to convert high-boiling-point viscous crude oil into lowerboiling-point products. Early refiners employed batch rather than continuous systems and used thermal cracking as the conversion process (see “Refining Glossary,” next page). In this type of cracking, large oil molecules are thermally decomposed to molecules of lower-boiling-point substances. The lower-boiling-point materials that are stable leave the system as cracked gas, gasoline and distillate in the kerosene-diesel boiling range. Other components that are less stable polymerize to form products heavier than the original crude. Thermal cracking to produce motor gasoline, or petrol, was the primary conversion process during the first part of the 20th century. Use of thermal processes peaked in the 1930s and subsequently declined as fluid-bed catalytic

cracking was introduced during World War II. Catalytic cracking eventually displaced thermal cracking as the primary conversion process, although mild thermal cracking is still in use at many small refineries. This displacement of the thermal process is due to catalytic cracking’s greater yields of high-octane gasoline with less of the heavy fuel oil and no coke by-product. Following the war, refining continued to mature and expand through use of sophisticated catalysts and automated process control. These improvements increased conversion levels and improved selectivity to desired products. 1. “Global Refining Capacity Increases Slightly in 2006,” Oil & Gas Journal 104, no. 47 (December 2006): 56–60. McKetta JJ Jr (ed): Petroleum Processing Handbook. New York City: Marcel Dekker, 1992. 2. ExxonMobil’s Energy Outlook 2006. http://www.exxonmobil. co.uk/Corporate/Citizenship /Imports/Energy Outlook06 /slide_9.html (accessed February 10, 2007). Meyer RF and Attanasi ED: “Heavy Oil and Natural Bitumen—Strategic Petroleum Resources,” USGS (August 2003), http://pubs.usgs.gov/fs/fs070-03/fs070-03.html (accessed February 10, 2007). 3. Nelson WL: Petroleum Refinery Engineering, 4th ed. New York City: McGraw-Hill, 1958.

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Refining Glossary Aromatics—a general term for petroleum hydrocarbons containing at least one ring with alternating double bonds. Batch processing—a production method in which the ingredients are mixed in a vessel and the required conditions applied; after a designated amount of time, the process is shut down and the vessel emptied. Bubble cap—a slotted cap placed on top of a vapor riser in a distillation column to promote vapor-liquid contact. The bubble cap-riser assemblies are arranged on horizontal trays in the column. Other common tray-contacting assemblies in the refinery include sieve trays and valve trays. Coke—a carbonaceous material formed by condensation reactions at high temperatures. Coking—a severe thermal cracking process on vacuum resid to produce coke and lighter products. The most common variant is delayed coking in which long residence times at high temperature are used to drive the process to nearly complete conversion. Continuous processing—a production method with the ability to produce a product without interruption. Cracking—splitting a carbon-carbon bond either by thermal means (coking) or with the aid of a catalyst (catalytic cracking, hydrocracking). Deasphalting—using a light hydrocarbon to bring asphalt out of solution. Distillate—a refinery stream that has been vaporized and condensed. Distillation—the separation of components based on differences in their volatility. Endothermic reaction—a chemical reaction that absorbs heat. Fouling—restricted flow in refinery lines or vessels as a result of coke formation, sludge accumulation or particle accumulation. Fractionation—a separation process based on concentration gradients. Fuel oil—a broad classification for liquid fuels produced in the refinery that range from distillates to heavy fuel oil. Gas oil—any distillate stream having a boiling point higher than that of heavy naphtha. Heavy oil—heavy, high-sulfur oil. Heavy oils are difficult to refine due to high levels of sulfur, condensed aromatics (asphaltenes) and metals. There is no universal definition for heavy oils but sulfur values are usually higher than 3.0% by weight, and gravity is usually at or below 20 to 22°API. Isomerization—transformation of a molecule into another form (the isomer) with the same molecular weight but a different structural arrangement. Naphtha—a distillation cut in the range of 32 to 220°C [90 to 430°F]; naphthas are usually classified according to process and boiling range. Naphthenes—a general term for petroleum hydrocarbons containing at least one saturated ring. Octane number—a measure of the resistance to autoignition (knocking) of the fuel. The octane number is the volume percentage of iso-octane in a mixture of n-heptane and iso-octane that has the same knock characteristics as the fuel in question. Olefin—a general term for petroleum hydrocarbons containing at least one carbon-to-carbon double bond. Paraffin—a general term for saturated petroleum hydrocarbons that contain no rings and have a carbon number greater than about 20. Petrochemicals—the generic name given to a broad range of products produced using by-product refinery streams as feed. Petrochemical building blocks such as ethane may come directly from refinery streams or be produced by a process such as naphtha cracking. Silica-alumina—the name given to the amorphous catalytic cracking catalyst base material. Silica-alumina for cracking catalyst is synthetically produced by combining sodium silicate, sodium aluminate and sodium hydroxide. Steam ejection—the passage of steam through a jet ejector to generate a vacuum. Straight run—refinery fluid streams cut directly from the crude oil. Three-way catalytic converter—a canister in automobile exhaust systems used to reduce emissions. The converter acts by reduction of nitrogen oxides to nitrogen and oxygen, oxidation of carbon monoxide to carbon dioxide and oxidation of unburned hydrocarbons to carbon dioxide and water. Vacuum resid—the bottom or heaviest stream from the crude-oil vacuum distillation tower. Visbreaking—mild thermal cracking. Zeolite—a silica-alumina mineral that has an open porous structure. Zeolites usually undergo further treatment by exchange with rare earths to produce the desired catalytic cracking catalyst properties.

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Refiners today confront the same challenge that their predecessors faced over a hundred years ago—refinery products must match marketplace demands. The current market demands a transportation-fuel product that boils below 345°C [650°F] with nearly zero sulfur content. The problem is that crude oil rarely occurs in that form. Light, sweet crude such as Brent and West Texas Intermediate with sulfur levels below 1.0% by weight have become scarce and expensive as the market has moved toward heavier crude with sulfur levels in the range of 1.0 to 3.0% by weight. Increased use of heavy oil with sulfur levels above 3.0% by weight has put additional demands on refineries.4 The quality difference between light and heavy oil shows up in the marketplace price that refiners pay for feedstock. The price differential between light crude (>40°API) and heavy oil (<20°API) varies with the market, with $9.00 per bbl being a typical value.5 With high demand for light transportation fuels, 70 to 90% of the product barrel now boils below 345°C.6 Refiners have met these challenges by installing more conversion and product-finishing capacity. In this article, we will examine how a refinery takes crude and converts it to finished products for the market. Separation Is the First Step All refineries have three primary sections: separation, conversion and finishing.7 Before processing crude, refiners must physically separate it into various molecular-weight ranges. This allows for tailored and selective conversion steps to operate efficiently. Products from these conversion steps are then treated in several finishing 4. Dealing with heavy oil has presented producers with additional challenges as well. Heavy-oil physical properties make most varieties very difficult to transport to the refinery by conventional means. Producers must decide whether to prepare heavy oil for shipping by dilution or by partial or full upgrading on site. 5. Davis NC: “Overview of Domestic Petroleum Refining and Marketing,” (February 5, 2007), http://www.eia.doe. gov/emeu/finance/usi&to/downstream/update/index.html (accessed February 13, 2007). 6. Davis P,Reynolds J, O’Neal A and Simmons K: Crude Oil and Its Refining. Richmond, California, USA: Chevron Technical University, 2005. 7. The terms product treating and finishing are often used interchangeably. 8. Speight JG: The Desulfurization of Heavy Oils and Residua. New York City: Marcel Dekker, 2000. Gary JH and Handwerk GE: Petroleum Refining Technology and Economics, 4th ed. New York City: Marcel Dekker, 2001. 9. In a reference to early refinery operations when thermal cracking was prevalent, these distillation units are still called the atmospheric and vacuum pipestills in many refining publications. 10. Hsu CS and Robinson PR (eds): Practical Advances in Petroleum Processing. New York City: Springer, 2006.

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steps to make them ready for sale. All these steps operate in concert to turn crude into thousands of products (below).8 The first step in any refinery is separation of the crude oil into component streams in a distillation unit. Crude oil contains thousands of individual compounds and at atmospheric

pressure these components can boil anywhere between 0°C [32°F] to more than 540°C [1,000°F]. Distillation is used to separate the crude into different boiling-range fractions for efficient conversion and cleanup downstream. Modern conversion refineries typically have two distillation towers in series—a tower operating

close to atmospheric pressure followed by a vacuum unit.9 These large towers often have the highest feed rate of any unit in the refinery. A large unit can process 32,000 m3/d [200,000 bbl/d] or more of crude oil. The towers contain trays or structured packing for vapor-liquid contacting, and heights of 45 m [150 ft] are common.10

Refining Operations Separation

Conversion

Gas plant

Butanes, butylenes

Finishing

Alkylation

Petrochemical Operations Products

Products

Liquefied petroleum gas, fuel gas, petrochemical feedstock

Ink Paintbrushes Telephones

Hydrotreating

Fishing lures

Gasoline

Deodorant 320°F

Reformer

Electrical tape

320 to 450°F Crude oil

Atmospheric 450 to 580°F distillation 580 to 650°F

Hydrotreating

Food preservatives

Kerosene

Safety glass

Hydrocracking Hydrotreating Catalytic cracking

650°F

Floor wax

Hydrogen

Kerosene, mid-distillate Naphtha, kerosene Heating oil

Hydrocracking Visbreaking

Synthetic rubber Petrochemical feedstock (gas, naphtha)

Vitamin capsules Insect repellant Paint

Fuel oil

Beach umbrellas

Gasoline, kerosene, diesel oil

Garden hoses

Fuel oil

Antihistamines

Nail polish Tennis shoes

660 to 880°F

Catalytic cracking

Vacuum distillation

880 to 1,050°F

Hydrotreating 1,050°F Deasphalter

Coking

Light ends

False teeth

Naphtha, kerosene

Shoe polish

Gasoline, kerosene Coke

Fan belts Aspirin Lipstick Parachutes

Insoluble

Asphalt

Soluble

Toothpaste Yarn

Solvent Extraction

Aromatic oil Lubricating oil, wax, grease Refinery products 100s to 1,000s

Anesthetics Ballpoint pens Heart valves Petrochemical products > 10,000

>Typical refinery process flow showing separation, conversion and finishing sections with end products (left). The products from most refineries number in the hundreds and may number in the thousands from conversion refineries if lubricating oil, wax and grease production are present. In some facilities, refinery gas and naphtha are sent to petrochemical plants for further upgrading—where the eventual end products number in the tens of thousands (right). (Adapted with permission from Speight, reference 8.)

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A

P

O

Bubble caps

R Bubble caps

LIQUID

V

Liquid

LIQUID

Tray

V

A

P

O

R

Liquid

V

A

P

O

R

LIQUID

Tray

>Distillation process. Crude-oil distillation is a thermal, physical separation into product boiling-range components. In an atmospheric crude-oil distillation unit, the feedstock is heated in exchangers and furnaces to about 370°C [700°F] (top). At this temperature, a significant portion of the crude vaporizes and moves up the distillation column, while the remaining liquids move down toward the bottom of the column. Vapors that escape to the top of the column are condensed to a liquid, and a portion is returned to the column as reflux. Throughout the column, liquid and vapors are in contact—internal elements such as trays or packing assist in making that contact (bottom). Inside the column, thermal layers are established that match the boiling-point ranges of the product streams. These product streams are withdrawn as side streams. Nitrogen level in the crude affects the color of the product streams. From the top of the column down, these product streams start as clear fluids and become progressively darker in color. The bottom stream from the atmospheric crude distillation tower is sent to a vacuum tower if that tower is present. (Adapted from Davis et al, reference 6.)

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The flow scheme through the atmospheric and vacuum towers is straightforward. After water and salt are removed, the crude oil is fed to the atmospheric tower (left). In the atmospheric tower, it is separated into several component streams—gas, naphtha, distillate and residue. The residue from this unit is sent to the vacuum distillation tower to recover additional liquids in the higher boiling-point ranges that will be used as feed for the critical conversion units. Vacuum distillation towers use steam ejection to generate a vacuum of 50 to 100 mm of mercury. This keeps temperatures low enough to avoid fouling on the internal sections of the tower. Although all refineries have distillation as the primary separation process, some locations have additional separation steps such as deasphalting and other extraction steps.11 The units downstream of the towers transform the separated fractions into products; this is where the real work takes place. Some units use sophisticated catalysts while others do their work using brute-force thermal methods. Temperatures in these units range from 4°C [40°F] in an alkylation reactor to 700°C [1,300°F] in a catalytic cracking regenerator vessel. Pressures may be as high as 20.7 MPa [3,000 psi] in a hydrocracker to near atmospheric level in a delayed-coking unit. The Conversion Workhorse Among the unique collection of elements in a refinery, the most crucial are the conversion units—for catalytic cracking, hydrocracking and coking. These units convert the high molecularweight oil fractions from separation into components that become finished products. Of these conversion units, the premier process is fluid catalytic cracking (FCC). Catalytic cracking was discovered in the 1920s using treated clay as a catalyst; Exxon commercialized the first fluidbed unit at its Baton Rouge, Louisiana, refinery in 1942.12 Since then, catalytic cracking has become the most widely used process for converting higher boiling fractions into gasoline and other products.13 The catalytic cracking process has a tolerance for a wide variety of feeds. A common feed is a nominal 340 to 540°C [650 to 1,000°F] fraction from the vacuum distillation tower. The FCC feed is preheated and injected into a moving stream of fluid catalyst from the regenerator at the reactor entrance (next page).14 The temperature of the catalyst stream is about 700°C [1,300°F] and cracking reactions happen quickly. The kinetics for breaking carbon-carbon

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bonds are complex and may involve multiple pathways and several secondary reactions. As a result of the various reactions, the catalyst leaving the reactor is deactivated from carbon deposition. The temperature at the top of the reactor outlet is typically in the range of 480 to 550°C [900 to 1,020°F].15 Operators control this temperature carefully, as it has an important effect on product distribution; lower temperatures favor distillate yield, while higher temperatures favor gasoline and light olefins. Although secondary reactions can be controlled to some degree by quenching at the top of the reactor, enough occur that the catalyst leaving the reactor is deactivated from carbon deposition. After separation, the deactivated catalyst passes to the regenerator vessel where the carbon deposits are burned off in controlled fluidized combustion using air or oxygenenriched air. The regenerated catalyst passes from the regenerator to the reactor to begin the process again. Temperatures in cracking regenerators can approach 730°C [1,350°F], and the vessel walls must be lined with refractory material to protect the steel shell. Large vessel diameters keep gas velocities low to minimize entrainment of the fine catalyst particles in the flue gas. The energy present in the regenerator flue gas is too valuable for discharge to the atmosphere. It is typically used to generate steam in a carbon monoxide boiler. Catalytic cracking units are heat balanced— the combustion of the carbon on the spent catalyst provides the energy required to preheat the feed and supply the endothermic reaction. Typically, about 70% of the energy from the combustion is required for feed preheating and the reaction. The other 30% is consumed by heat losses, preheating air to the regenerator and steam generation. A large catalytic cracking unit can have 545 tonnes [600 tons] of catalyst circulating at mass rates of tons per second. Tuning of the simultaneous mass and energy balances is the key to successful operation. Although the catalytic cracking process has seen many improvements during the last 75 years, none has had more effect than improvements in the catalyst itself. The key property of any cracking catalyst is the presence of an active acid site on a solid surface. Early FCC catalysts were synthetic silica-alumina. These catalysts had a random distribution of catalyst pores, and pore diameters were much larger than molecular sizes.

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Products

Disengaging vessel Flue gas Spent catalyst

Steam

Regenerator Reactor Air, or air + O2

Steam Regenerated catalyst

Feed

>Fluid catalytic cracking unit at a Chevron refinery (left). The process uses a catalyst with an average particle size of about 70 microns—similar in size to flour or talcum powder. The catalyst is fine enough that it behaves as a fluid when aerated by a gas. In a typical operation (right), feed is injected into a stream of fluidized catalyst from the regenerator and the resultant mass moves through the reactor. The reaction is fast and the products, spent catalyst and unconverted feed move into the disengaging vessel where hydrocarbons and catalyst are separated. Products and unconverted feed go to fractionation. The spent catalyst goes to the regenerator vessel, and regenerated hot catalyst moves through a large slide valve to the feed injection point where the process begins again. (Adapted from Davis et al, reference 6.)

The breakthrough discovery in cracking catalysis occurred in the 1960s with the introduction of zeolites to the silica-alumina catalyst base. Zeolites allowed preparation of catalysts with a controlled three-dimensional structure having molecule-sized pores.16 Control of pore size allows high molecular-weight aro-

matic compounds to be excluded, thereby reducing undesirable reactions to carbon. These improvements sharply increased catalyst activity and improved selectivity to desirable products. Additional improvements to cracking catalyst activity and selectivity continue to the present day.

11. Some refineries use light hydrocarbons such as propane to precipitate asphaltenes in a solvent extraction step. The resultant deasphalted oil may be used in conversion steps or to produce lubricants. 12. The first use of treated clays to catalytically crack petroleum fractions to gasoline is attributed to Eugene Houdry. Commercial implementation during the late 1930s employed a bead catalyst that shuttled between the reactor and the regenerator (moving beds).

Magee JS and Dolbear GE: Petroleum Catalysis in Nontechnical Language. Tulsa: PennWell Publishing Company, 1998. 13. Gary and Handwerk, reference 8. 14. Gary and Handwerk, reference 8. Hsu and Robinson, reference 10. 15. Hsu and Robinson, reference 10. 16. Venuto PB and Habib ET Jr: Fluid Catalytic Cracking with Zeolite Catalysts. New York City: Marcel Dekker, 1979.

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Another important refinery conversion process is hydrocracking. Hydrocracking combines breaking of carbon-carbon bonds with the addition of hydrogen. The process was originally developed by I.G. Farben in 1927 to convert coal into gasoline.17 Hydrocracking may take many forms depending on the application. These range from mild hydrocracking of heavy vacuum gas oils at 5.5 to 10.4 MPa [800 to 1,500 psi] hydrogen partial pressure to severe hydrocracking of residual oil at 20.7 MPa [3,000 psi]. Hydrocracking is a flexible process that can be designed to maximize gasoline or diesel production, to pretreat catalytic cracker feed, or to produce base oils for manufacturing lubricants. Regardless of the application, hydrocracking reactors typically use a shaped catalyst loaded in downflow, fixed beds.18 Nearly all hydrocracking catalysts use a silica-alumina base with a metal component such as platinum or palladium. The hydrocracking catalyst becomes deactivated over time as carbon deposits build up and cover active sites. This necessitates a corresponding gradual increase in temperature to maintain desired conversion targets. After two or three years, hydrocracking catalyst activity decreases to a point at which the unit must be shut down and the catalyst regenerated or replaced. Regeneration is accomplished by burning off the carbon deposits in situ. Hydrocracking catalysts may go through several cycles before they must be replaced and precious metals recovered. Although hydrocrackers are expensive to build, recent interest in them has been spurred by high demand for light motor fuels and their ability to produce specialty products such as lubricant base oils. Environmental concerns about refinery product contaminant levels have also contributed to hydrocracking growth. The last important refinery conversion process is coking. Coking deals with the heaviest part of the barrel—those components with boiling points exceeding 540°C [1,000°F] known as vacuum resid. Catalytic cracking can accommodate some vacuum resid, and direct sale of fuel oil and asphalt is another outlet. However, because of increased demand for light products and more reliance on heavy oils, vacuum-resid supply often exceeds demand. The refiner must use a process like delayed coking to convert the excess vacuum resid into useful products (above right). Unlike the majority of other refinery process steps, no catalyst is used in coking. Time and temperature are used to convert the vacuum resid by means of two reaction pathways—

Summer 2007

Drilling water Process gas

Light coker naphtha Heavy coker naphtha

Coke drums

Light coker gas oil Residuum feed

Heavy coker gas oil Furnace

Coke (+ water)

Feed plus recycle Fuel

>Delayed coking unit at a Chevron refinery (top). Residuum feed plus recycled material is heated to more than 480°C [900°F] in the feed preheat furnaces (bottom). The temperature is high enough and residence time in the furnaces long enough that thermal cracking of the feed occurs as the discharge enters the coke drums. About 70% of the thermally cracked product vaporizes; gas leaves the coke drum and moves to the product fractionation tower. The other 30% undergoes condensation reactions and is transformed into a solid, carbon-rich coke that eventually fills the drum. Pairs of drums are employed and when a drum nears capacity, the drums are switched and coke is physically removed. Initially, the drum is steam-stripped to remove additional hydrocarbons and then quenched with water. When the drum has cooled, the top and bottom heads are removed, and the coke is drilled out using high-pressure water jets. Cycle time on delayed cokers is usually 18 to 24 hours. The solid coke is discharged into a pit and handled as a solid with grinders and a conveyor for moving the material to shipping. (Adapted from Davis et al, reference 6.)

thermal cracking and condensation. Liquid products from a delayed-coking unit span the entire range from naphtha to heavy gas oil. Because of the high concentration of olefins and other contaminants, coker product liquids must undergo hydrotreating so they can be blended into finished products. Depending on the feed quality and coke-drum temperature, several varieties of solid coke may be produced.

Heavy, high-sulfur crudes tend to produce fuel-grade coke, a low-value solid fuel that can be blended with coal. Lower-sulfur crudes can produce higher-value anode-grade coke that is converted to anodes for aluminum manufacturing. Although delayed coking is the most common coking variant, some process capacity is installed as fluid coking—similar to fluid catalytic cracking but without the catalyst.

19

2004

Australia 2004

2005 2008

USA 2004 2004

2005

Canada Other EU 2004

2005 Korea

2004

2006 Japan

2006 Germany

2004

Gas oli ne- sulfur tar get,m pp 1,000

100

10

1

>Gasoline-sulfur targets. Reduction of sulfur in motor gasoline is an important environmental goal. Sulfur in gasoline is converted to sulfur dioxide in the automobile exhaust, and that acts as a poison to the three-way catalytic converter. Reducing gasoline-sulfur content increases exhaust-gas converter efficiency thereby decreasing toxic emissions. During the past few years, governmental agencies worldwide have targeted motor gasoline as a candidate for large reductions in sulfur content. For example, Japan reduced sulfur in gasoline from 100 ppm in 2004 to 10 ppm in 2006, and Germany achieved 10 ppm in 2004. The concept of low sulfur levels in gasoline is becoming the norm rather than the exception. Sulfur levels in diesel fuel are following a similar path. (Adapted from Hsu and Robinson, reference 10.)

Finishing Completes the Picture As important as the conversion units are to the refinery, the story does not end with them. Once the large molecules in the crude oil have been converted to a range of smaller ones, they must undergo one or more finishing steps. The most widely used process in the finishing arsenal is hydrotreating—a generic name given to a wide range of hydrogenation or hydrogen-addition steps. The most common reason for using hydrotreating on any refinery stream is sulfur removal. In addition to removing a substantial amount of sulfur, hydrotreating may also target other compounds containing metals and nitrogen—and occasionally olefins and aromatics may be hydrogenated. Hydrotreaters exhibit a wide range of operating conditions. These units span the range from simple kerosene units operating at 1.7 MPa [250 psi] hydrogen partial pressure to units operating at 10.4 MPa [1,500 psi] and treating 340 to 540°C [650 to 1,000°F] material. Hydrotreating can be used either in a standalone mode to make a product ready for sale or as a pretreatment for molecular rearrangement. The demand for ever-increasing volumes of high-quality motor gasoline has heightened the 17. Gary and Handwerk, reference 8. 18. Fixed-bed reactors are vertical, cylindrical vessels filled with catalyst particles of controlled size, surface area and pore distribution. 19. Mouawad J: “No New Refineries in 29 Years, But Project Tries to Find a Way,” The New York Times (May 9, 2005), http://select.nytimes.com/search/restricted/ article?res=F30611FC39540C7A8CDDAC0894DD404482 (accessed January 31, 2007). 20. http://omrpublic.iea.org/refinerysp.asp (accessed April 16, 2007). 21. Hsu and Robinson, reference 10.

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focus on molecular rearrangement processes— reforming, alkylation and isomerization. This rearrangement is necessary because the gasoline-boiling-range streams from conversion and hydrotreating are rich in straight-chain paraffins and naphthenes that have low octane numbers. Rearrangement transforms these lowoctane components into higher octane branched paraffins and aromatics. All of these processes are catalytic. Reforming and isomerization are conducted in the gas phase using either precious metals on alumina (reforming) or zeolite on alumina (isomerization) as a catalyst. Alkylation, on the other hand, is conducted in the liquid phase using either sulfuric or hydrofluoric acid as a catalyst. The products produced in all of the conversion and finishing steps are almost ready for sale. Straight-run products may need additional treating steps for drying and sulfur removal, and many products will require some blending and additives to meet final sales specifications. Depending on the location, gasoline usually requires additives for oxidation, metals and corrosion inhibition plus anti-icing. Depending on the complexity and product requirements, some refineries may have units to produce asphalt, wax, lubricating oils and greases. Refining Present and Future There has never been a more challenging situation for refineries than the one they currently face. Those that survived the profit margin collapse and capacity glut of the late 1980s and early 1990s now see their capacity limits stretched. No new refineries have been

built in the USA since 1976 despite a 45% increase in gasoline usage over the same period.19 Refiners have dealt with capacity constraints by installing numerous debottlenecking projects. In some cases, these projects are new construction in an existing refinery while others may add a new catalyst or improved process control. In addition to the challenges presented by capacity constraints, refineries worldwide must now cope with greater quantities of heavy oil as conventional sweet crude becomes scarce. Refining heavy oil requires significantly more severe conditions for a given set of product specifications. This puts an additional strain on refinery costs. Refineries prosper or fail on the profit margin they make on each barrel of crude oil processed. However, refineries are caught between the desire of the public for low fuel prices and the producers who want to sell their crude oil at the highest price. Both the oil producers and the public believe that prices are set by the refinery and that refinery profits are high. In reality, neither the producer nor the refiner sets the price, and average worldwide refining margins are generally modest.20 Prices are set on the various worldwide financial exchanges that trade contracts on crude oil and refined products. Those prices are a minute-to-minute reflection of how investors view future needs for energy and petroleum products. All parties are at the mercy of those estimates. Like crude-oil producers, refiners have also had to deal with the challenges presented by environmental regulatory legislation. Environmental regulations started to tighten in 1970, and the trend has accelerated in recent years. During this period, refineries have made remarkable progress in cleaning up their direct and indirect emissions. Refineries have reduced direct emissions by flue-gas scrubbing and control systems, optimization of furnaces and increased monitoring to reduce hydrocarbon emissions from valves and fittings.21 Refineries have also become more energy efficient, thereby reducing production of carbon dioxide. Nowhere has the environmental push been stronger than the trend toward clean transportation fuels. This trend has quickly spread worldwide (above left). Refiners are a vital part of the team that converts crude oil into useful products. As more of that crude oil comes from heavy oil and higher-sulfur sources, refineries will have to continue to develop new technologies to supply the world with products that are both clean and affordable. —DA

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