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The process of refining begins with the delivery of crude oil—a mixture of thousands of different hydrocarbon compounds that must be separated into fractions of varying boiling ranges in order to be used or converted into products such as gasolines, diesel fuels, and so on. Crude oils from different sources vary widely in terms of density (gravity), impurities (sulfur, nitrogen, oxygen, and trace metals), and kinds of hydrocarbon compounds (paraffins and aromatics). In general, the heavier the crude oils, the less transportation fuel (gasoline, diesel fuel and jet fuel) boiling-range components are contained in the crudes. The average crude oil charged to U.S. refineries in 1998 contained about 20 percent material in the gasoline boiling range and about 25 percent in the middle distillate (diesel and jet fuel) boiling range. The U.S. market requirements are about 50 percent gasoline and 35 percent middle distillate fuels per barrel of crude oil charged to U.S. refineries.


Crude oils are classified by major hydrocarbon type (paraffinic, intermediate, or naphthenic), gravity (light or heavy), and major impurities—high sulfur (sour), low sulfur (sweet), high metals, etc. Everything else being equal, the heavier the oil the lower the value of the oil, because a smaller percentage of that particular crude is in the transportation fuel boiling range. The boiling ranges of the heavier fractions can be reduced, but the additional processing is costly, adding anywhere from fractions of a cent to several cents per gallon. The same is true of the sulfur, nitrogen, oxygen, and metal contents of crude oils. The impurities have to be removed by reaction with hydrogen, and hydrogen processing is very expensive.

Paraffinic crude oils are defined as those crude oils containing waxes, naphthenic crude oils as those containing asphalts, and intermediate crude oils those containing both waxes and asphalts. Usually the residues—material boiling above 1050°F (565°C)— of naphthenic crude oils make good asphalts, but the intermediate crude oils can contain enough wax so that the asphaltic part may not harden properly, and therefore they cannot be used to produce specification asphalts.

Refinery processes are available to reduce the boiling points of components of the crude oils that boil higher than the transportation fuels by cracking the large high-boiling-point molecules into smaller molecules that boil in the desired transportation fuel boiling range. Lighter materials can also be converted to transportation fuels (usually gasoline) by processes such as alkylation or polymerization. There are also processes to improve the quality of the transportation fuel products because the crude oil components with the proper boiling range do not have the other characteristics required. These include octane and cetane numbers for gasoline and diesel fuel, respectively, and low sulfur and nitrogen contents for gasoline, diesel, and jet fuels.

Over 50 percent of the crude oils used in the United States are imported, because U.S. crude oil production has passed its peak and has been declining in recent years. Also, other countries (Mexico, Saudi Arabia, and Venezuela) have been buying full or part ownership into U.S. refineries in order to ensure there will be a market for their heavy, high-sulfur crude oils. These efforts to ensure a market for their imported crude oils have resulted in more equipment being installed to crack the very heavy portions of the crude oils into as much transportation fuel boiling-range material as is economically feasible. As of January 1, 1999, U.S. refineries had the ability to crack more than 50 percent of the crude oil charged to the refineries. As the demands for heavier products decreases, additional cracking equipment will be added to some U.S. refineries to increase the cracking ability to 60 percent or higher. Also, as the demand for cleaner burning transportation fuels with lower concentrations of aromatics and olefins increases, additional process equipment will be added to produce larger volumes of alkylates.

Most of the U.S. refineries are concentrated along the Gulf Coast, because most imported crude oils come from Venezuela, Mexico and Saudi Arabia and a large amount of U.S. domestic crude oil is produced near the Gulf Coast in Texas, Louisiana, Mississippi and Oklahoma. California also has a concentration of refineries that process crude oil from deposits in California and Alaska, in order to avoid the costs of transferring crude oils and products over or around the Rocky Mountains while also satisfying the large demands for transportation fuels in the West. These logistics explain in large part why over 54 percent of U.S. refining capacity is in the states of Texas, Louisiana, and California. Texas contains the most with more than 26 percent, Louisiana is second with almost 16 percent, and California is third with more than 12 percent. Environmental regulations, resistance to "having a refinery in my neighborhood," and economics have stopped the construction of completely new refineries in the U.S. since the 1970s. It is improbable that any will be built in the foreseeable future. Since the mid-1970s, all new complete refineries have been built overseas.

Because transportation fuels vary in boiling range and volatility depending upon the type of engine for which they are suitable, refineries are designed to be flexible to meet changes in feedstocks and seasonal variations in transportation demands. Typically, spark ignition engines require gasolines and compression ignition engines (diesels) require diesel fuels. Jet fuel (similar to kerosene) is used for most commercial and military aircraft gas turbines. Jet fuel demand fluctuates widely depending on the economy and whether the United States is involved in military operations. Most of the refineries in the United States are fuel-type refineries; that is, more than 90 percent of the crude oil feedstocks leave the refineries as transportation or heating fuels. Although there are other profitable products, they are small in volume compared to the fuels and it is necessary for the refinery to make profits on its transportation fuels in order to stay in operation. In 1999, there were 161 refineries in the United States, owned by eighty-three companies, and having a capacity of over 16,000,000 barrels per day (672,000,000 gallons per day). Worldwide, there are over 700 refineries with a total crude oil feed rate of more than 76,000,000 barrels per day. In the United States, for refinery crude oil feedstock capacities and crude oil purchases throughout the world, the standard unit describing amount is the barrel. The term barrel is outmoded and refers to the 42 U.S. gallon capacity British

Starter Material Boiling Point or Range Product Uses
 °F °C   
Methane & Ethane-259°F161°CFuel gasRefinery fuel
 -132°F- 91°C  
Propane- 44°F- 42°CLPGHeating
i-Butane+11°F -12.2°C Feed to alkylation unit
n-Butane31°F-0.5°CLPG, lighter fluid, gasolineGasoline blending or to LPG
Propylene and butylenes   Feed to alkylation or polymerization units
Light naphthas80-180°F27-82°CLight gasolineGasoline blending or isomerization unit
Heavy naphthas180-380°F82-193°CHeavy gasolineCatalytic unit feed
Kerosine380-520°F193-271°CKerosineJet fuel
Atmospheric gas oil520-650°F271-343°CLight gas oilBlending into diesel fuels and home heating oils
Vacuum gas oils650-1050°F343-566°C Feeds to FCCU and hydrocracker
Vacuum resid1050°F+566°C+Vacuum tower bottoms (VRC)Heavy and bunker fuel oils, asphalts

wooden salted-fish barrel used to haul crude oil to the refineries in horsedrawn wagons in the later part of the nineteenth century. Most of the world uses either metric tons or cubic meters as the unit of measurement.


All refineries are similar and contain many of the same basic types of equipment, but there are very few that contain exactly the same configuration, due to differences in the crude oils used as feedstocks and the products and product distributions needed. In addition, most refinery processing is very expensive, and many of the smaller companies do not have the necessary capital to install the latest highly capital-intensive technology such as alkylation units and hydrocrackers. Instead they use less costly units such as fluid catalytic cracking units (FCC) and polymerization units. However, except for the least complicated refineries, topping and hydroskimming refineries, they all have processes to change boiling range and improve quality.

A small number of refineries produce lubricating oils, but the total volumes produced are only about 3 percent of crude oil charged to U.S. refineries. Processes to make lubricating oil blending stocks are expensive from both capital and operating costs viewpoints. Nevertheless, the business is still profitable because lubes demand high retail prices. Older processes use solvent extraction to improve the temperature-viscosity characteristics (viscosity index) and low-temperature refrigeration tech-nologies, such as dewaxing, to lower the pour points of the lube oil blending stocks. Newer plants use selective hydrocracking and high-pressure hydrotreating to produce high-quality lube oil blending stocks. The newer equipment is so expensive that many of the new facilities are joint projects of two or more companies in order to gain enough volume throughout to justify the high capital investments.

Some refineries also install processes to produce petrochemical feedstocks. However, from a volume viewpoint, it is not a large part of refinery income. Even though profit margins can be high, most refineries restrict their capital investments to those needed to produce transportation fuels. The most common petrochemical feedstocks produced are olefins (chiefly ethylene and propylene) and aromatics (benzene, methylbenzene [toluene], ethylbenzene, and xylenes [BTX compounds]). BTX compounds are produced in a catalytic reformer by operating at high reactor temperatures to produce 102 to 104 research octane products containing over 75 percent aromatics. Using solvent extraction, fractionation, and adsorption technologies the products are separated into individual aromatic compounds for sale as petrochemical feedstocks.

Topping and Hydroskimmimg Refineries

The topping refinery (see Figure 1) is the simplest type of refinery, and its only processing unit is an atmospheric distillation unit which topsthe crude by removing the lower–boiling components in the gasoline, diesel fuel, and diesel fuel boiling ranges (those boiling up to 650°F [343°C]). The bottoms product from the atmospheric distillation unit (atmospheric resid, atmospheric reduced crude, or ARC) is sold as a heavy fuel oil or as a feedstock to more complex refineries containing conversion equipment that can convert the high–molecular–weight components into transportation fuel boiling–range products. Until recently the topped components could easily be converted into retail products by blending additives (such as lead compounds) into them. When lead compounds were banned from gasolines in the United States, it was necessary to add equipment to improve the octanes of the gasoline boiling–range components. Catalytic reforming units increased the octanes of the naphthas by converting paraffin molecules into aromatic compounds plus hydrogen. As a result, a topping refinery producing unleaded gasoline is a hydroskimming refinery.

Conversion and Integrated Fuels Refineries

Although a small amount of crude oils charged (less than 5 percent) to U.S. refineries is converted to specialty products, the remainder is either used in the refinery as a fuel or is processed into asphalt or fuel products including motor fuels and heating oils. The market for heavy fuel oils—those with boiling ranges above 650°F (343°C)—in the United States is less than 7 percent of the crude oil charged to U.S. refineries. It is therefore necessary to change the boiling ranges of the heavier portions of the crude to meet the product demands of the transportation fuels. Refineries with the necessary boiling-range conversion equipment are integrated or conversion refineries (see figure 2). The majority of the conversion equipment is to reduce boiling point—these are cracking units. When the molecules are cracked to reduce boiling range, secondary reactions produce some light hydrocarbons with boiling points too low for typical transportation fuels. Conversion equipment is also included to increase the boiling points of these components to permit blending into gasolines. As a result, about 70–80 percent of the crude oil charged to U.S. refineries is converted into gasolines, diesel and jet fuels, and home heating oils.


Refineries produce more than 2,000 products, but most of these are very similar and differ in only a few specifications. The main products, with respect to volume and income, are liquefied petroleum gases (LPG), gasolines, diesel fuels, jet fuels, home heating oils (No. 1 and No. 2), and heavy heating oils (No. 4, No. 5, No. 6, and bunker fuel oil). Some refineries also produce asphalts and petroleum coke.

LPGs are gases that are liquefied at high pressures—up to 250 psig (17 bars)—and consist mainly

Generic name Characteristics
NaphthaAny liquid hydrocarbon material boiling in the gasoline boiling range
MiddleLiquid hydrocarbons boiling in the
distillatejet fuel, diesel fuel, and home heating oil ranges
Gas oilHydrocarbons boiling at temperatures above 400°F (205°C) that have been vaporized and reliquefied
CokeA solid residue from cracking operations, mostly carbon but with a small amount of high-molecular-weight hydrocarbons

of mixtures of propane and butanes. These are sold in pressurized cylinders and are used for heating. Their selling price is related to the heating value.

Gasolines are the largest volume refinery products. In 1998, for instance, more than 330,000,000 gallons were consumed each day in the United States. This amounts to more than one million tons per day. The best known specifications for gasoline are octane numbers and Reid vapor pressure (RVP). The octanes are numbers determined by laboratory tests and can be related to performance of gasolines at normal road operating conditions. Octane numbers measure the resistance of the gasoline to self–ignition (knocking) and are determined by comparison with reference fuels. Self-ignition causes a decrease in engine efficiency and power, and when it occurs there are noticeable reductions in mileage and acceleration. Research octane number can be correlated with city driving performance (RON) and motor octane number (MON) with highway driving performance. Federal regulations require that the arithmetic average of these octanes ([RON + MON]/2) be posted on the pumps dispensing the gasolines. In 1998, about 70 percent of the gasolines sold in the United States were regular grade, and 30 percent premium grades. Regular gasoline posted octanes are 87 for lower elevations and 85 or 86 at higher elevations (above 3,000 feet). The octane requirement of an engine decreases with elevation. Refiners try to produce gasolines with the RON and MON as close together as possible, so their gasolines perform equally well for both city and highway driving but it is not practical. Refinery processing equipment has major effects on the sensitivity to driving conditions of the gasolines produced. Typically the RON and MON of gasolines will differ by six to twelve octane numbers (RON–MON). For gasolines the RON is always higher than the MON.

Reid vapor pressure determines ease of starting, engine warmup time, and tendency for vapor lock to occur. Vapor pressure is regulated by the addition of n–butane to the gasoline mixture. During summer months, EPA regulations limit the maximum vapor pressure of gasolines to as low as 7.2 psi in the southern U.S. and Rocky Mountain areas in order to reduce hydrocarbon vapor emissions into the atmosphere. During the cold months of winter, RVP is increased in northern areas to as high as 14 psi to make starting of cold engines possible and for the engines to warm up quickly. Normal butane not only increases RVP, but it also acts as an octane booster. During the summer months when less n–butane can be blended into gasolines, additional amounts of some other, more costly, octane booster must be added to compensate.

The cetane number determined in the laboratory by comparison with reference fuels is of value in that it is an indication of the ease of self–ignition. Diesel engines do not use a spark to ignite the fuel–air mixture in the cylinder but rely on the diesel fuel to self–ignite when injected with a high–pressure injection pump into the hot compressed air in the cylinder. The quicker the fuel self–ignites, the more efficient the engine. Many small refineries do not have cetane number determination equipment, so they substitute a cetane index equivalent to the cetane number and calculated from the fuel's gravity and average boiling point. The Environmental Protection Agency (EPA) requires that highway diesel fuels sold in the United States must have a cetane index (CI) of at least 40 and a sulfur content of less that 0.05% by weight (500 ppm). During 1998, almost 150 million gallons of diesel fuels and 60 million gallons of jet fuel were used in the United States per day.


Refineries are unique businesses in that they operate on small profits per unit volume of product but produce very large volumes of product. This means that a regulatory adjustment (such as sulphur content) that creates a small change in operating costs per gallon of product (fractions of a cent) can mean the difference between profit and loss. The industry therefore strives to optimize refinery operations to lower costs and to improve efficiency.

One of the significant problems for refinery is the small amount of water emulsified in the crude oils coming into refineries. This water contains inorganic salts that decompose in the process units and form compounds that are corrosive to equipment and poison catalysts used in the processes. To prevent these costly problems, the first process in the refinery, desalting, reduces the water and salt content of the crude oils. Following desalting, the crude is sent to the distillation units (crude stills) to be separated into fractions by boiling range. The first of the crude stills, the atmospheric distillation unit, vaporizes and separates those components boiling below about 650°F (345°C) into four general categories; butane and lighter (methane, ethane, and propane) gases, light and heavy naphtha fractions, kerosene, and atmospheric gas oil. (Gas oil is a generic name for any hydrocarbon boiling above the end boiling point of gasoline that has been vaporized and condensed into a liquid.) The unvaporized material boiling above 650°F is removed from the bottom of the distillation column as vacuum resid or atmospheric reduced crude (ARC). The naphtha fractions are in the gasoline boiling range but, before blending into gasoline, their quality has to be improved by increasing their octanes and reducing the sulfur contents. The kerosene is hydrotreated (reacted with hydrogen) to reduce the sulfur content and blended into jet fuel. And the atmospheric gas oil is hydrotreated to reduce the sulfur content and is blended into diesel fuels and home heating oils (No. 1 and No. 2 heating oils).

The atmospheric reduced crude is the feedstock for the vacuum distillation unit. To prevent thermal decomposition (cracking) of the higher boiling point hydrocarbons in the crude oil, the pressure in the vacuum distillation fractionation column is reduced to about one-twentieth of an atmosphere absolute (one atmosphere pressure is 14.7 psia or 760 mm Hg). This effectively reduces the boiling points of the hydrocarbons several hundred degrees Fahrenheit. The components boiling below about 1050°F (565°C) are vaporized and removed as vacuum gas oils, the unvaporized material is removed from the bottom of the unit as vacuum reduced crude (vacuum resid or VRC). The vacuum gas oils are sent as feedstocks to either fluid catalytic cracking units or to hydrocrackers. The fluid catalytic cracking units crack the vacuum gas oils into gasoline blending stocks (up to 70 percent by volume on feed) and gas oil blending stocks for diesel fuels and home heating oils. The gasoline blending stocks have octane numbers in the high eighties and, if the sulfur contents are sufficiently low, can be blended directly into gasolines. The gas oil blending stocks have low cetane numbers and poor burning characteristics that limit the amounts that can be blended into diesel fuels and home heating oils.

If the crude oils from which the vacuum reduced crudes are made have the proper qualities (low wax and high asphaltenes), the vacuum-tower bottoms can be blended into asphalt products and sold to pave roads and make roofing materials and sealants. The vacuum reduced crudes also can be sold as heavy fuel oils or used as feedstocks to a severe thermal cracking unit (coker) to convert them into lower boiling hydrocarbons plus solid coke residues. The coker converts the vacuum tower bottoms into feedstocks for other refinery processing units to make gasolines, light heating oils, and, if used as hydrocracking unit feedstocks, produce gasoline, diesel fuel, and jet fuel blending stocks. Historically, the heavy fuel oils have sold, on a volume basis, for about 70 percent of the prices paid for the crude oils from which they were produced. When crude oil is selling for twenty dollars per barrel, heavy fuel oil will be selling for about fourteen dollars per barrel. This discounting is necessary because the amount of heavy fuel oil available exceeds demand. The alternate cost of processing the vacuum tower bottoms in the refinery is much higher than the cost of processing crude oil. The vacuum reduced crudes sell at a loss, or they are converted into salable products by processing the liquid products from a coker in other refinery processing units. The coke produced by the coker can be sold as a fuel, to make anodes for aluminum production, or to make electrodes for electric steel furnaces.

Fluid catalytic cracking units (FCC or FCCU) are the major processing units to reduce boiling ranges of those crude oil components that have boiling points higher than the final boiling points of the transportation fuels—typically above 650°F (343°C). These units circulate finely divided (about the size of very fine sand particles) silica-alumina-based solid catalyst from the reactor to the regenerator and back. The reactor operates at temperatures between 950 and 1,100°F (510–595°C) to crack the large molecules in the gas oil feed selectively into smaller molecules boiling in the gasoline boiling range of 80–400°F (27–205°C). When the cracking takes place in the reactor, coke is also produced and is laid down on the surface of the catalyst. This coke layer covers the active cracking sites on the catalyst, and the cracking activity of the catalyst is reduced to a low level. Conveying the catalyst to the regenerator, where the coke is burned off with air, restores the catalyst activity. This cycle is very efficient: the heat generated by burning the coke off the spent catalyst in the regenerator supplies all of the heat needed to operate the unit. The regenerated catalyst leaving the regenerator has had its activity restored to its original value and at a temperature of about 1,300°F (705°C) is returned to the riser–reactor and mixed with fresh feed to continue the cracking reactions. By controlling the reactor temperature, the conversion of the feed to gasoline boiling range components can be maximized during the summer when gasoline demand is at its highest. In practice, up to 70 percent by volume of the product is in this boiling range. The product is rich in aromatic and olefinic compounds, which makes the high quality FCC gasoline very suitable for blending into the final refinery gasoline products. The remainder of the feed is converted into butane, lighter gases, and catalytic gas oils (typically called cycle gas oils) that are blended into diesel fuels or home heating oils, or used as feedstocks to hydrocrackers. During the winter, when gasoline demand is lower and home heating oil is needed, the severity of the operation is lowered by reducing the reactor temperature, and the yields of the cycle gas oils stocks used for blending into home heating oils and diesel fuels is more than doubled. The gasoline boiling-range products are reduced by one-quarter to one-third. The butane and lighter gases are separated into components in the FCC gas recovery plant. The propylenes, butylenes, and isobutane are used as feedstocks to alkylation units to make alkylate gasoline blending stocks. Alkylates have blending octanes in the nineties and have low sensitivities to driving conditions (they perform equally well for highway and city driving with RON and MON within two numbers of each other). The hydrocarbons in alkylates are also less environmentally damaging and show less health effects than olefins or aromatics. For those refineries without alkylation units, the propylenes can be used as feedstocks to polymerization units to produce polymer gasoline blending stocks. The polymer gasoline has a blending octane of approximately 90 but performs much more poorly under highway driving conditions than in the city (about sixteen numbers difference between the RON and MON).

Some refineries have hydrocracking units in addition to the FCC unit. Hydrocracking units operate at high hydrogen pressures and temperatures and are constructed of high-alloy steels. This makes them very expensive to build and operate. They are able to use feedstocks containing high concentrations of aromatics and olefins and produce jet fuel and diesel fuel products as well as naphthas for upgrading and blending into gasolines. The FCC units operate most efficiently with paraffinic feedstocks and produce high yields of high-octane gasoline blending stocks. Hydrocrackers give higher yields than FCC units, but the naphtha products have octanes in the seventies and the heavy naphtha fraction—180–380°F (82–195°C)— must be sent to the catalytic reformer to improve its octane. It is possible to make specification jet and diesel fuels as products from the hydrocracker.

In any cracking process, secondary reactions produce light hydrocarbons whose boiling points are too low to blend into gasolines. These include both olefins and paraffins. Olefins contain at least one double bond in each molecule and are very reactive whereas paraffin molecules contain only single bonds and are considered unlikely to undergo chemical reactions. Some of the light hydrocarbon olefins produced can be reacted with each other (polymerization) or with isobutane (alkylation) to produce high–octane hydrocarbons in the gasoline boiling. The olefins used are propylenes and butylenes; ethylene is also produced from cracking operations but is not used in refinery processing.

Crude oil components with boiling ranges in the gasoline blending range have low octanes, and the octanes must be increased in order to make a product suitable for modern automobiles. For light naphthas containing molecules with five and six carbons (pentanes and hexanes), octanes can be improved from thirteen to twenty numbers on the average by isomerization processes. These processes convert normal paraffins into isoparaffins that have more compact molecules with higher octane numbers. The heavy naphthas with hydrocarbons containing from seven to ten carbon atoms, have their octanes increased into the nineties by converting paraffin molecules into aromatic molecules by reforming the molecules into ring structures and stripping off hydrogen. This process is catalytic reforming. Catalytic reforming is the only refinery process in which the operator has any significant control over the octane of the product. The more severe the operation (the higher the temperature in the reactor), the greater the percentage of aromatics and the higher the octanes of the products—but the smaller the volume of products produced. Usually the units are operated to produce products (reformate) with research octane numbers (RON) in the range of 96 to 102 to be blended with other naphthas to give the desired quality (pool octanes) sold to consumers.

Other refinery processes used to improve product quality include hydrotreating (hydrodesulfurization, hydrodenitrogenation, and demetallization), sweetening, and visbreaking. Hydrotreating reduces impurity contents of all of the impurities except metals by reacting hydrogen with the impurity to produce low-boiling compounds that are gases and can be separated from the liquid material. These reactions are carried out at high temperatures and pressures in reactors filled with catalysts containing metals that promote the reaction of hydrogen with the impurity. Hydrogen reacts with sulfur to form hydrogen sulfide, with nitrogen to produce ammonia, and with the molecules containing metals to deposit the metals on the catalyst supports. The processes operate at temperatures between 600°F (315°C) and 750°F (400°C) and pressures from 400 psig (27 bars) to 1600 psig (110 bars). Because these processes operate with hydrogen at high temperatures, the equipment is made of very expensive high–alloy steels. Energy and hydrogen costs result in high operating costs, much higher per barrel of feed than the FCC unit.

Refiners use sweetening processes to remove mercaptans that give a very unpleasant odor to gasolines and middle distillates (the skunk uses mercaptans to protect itself). This is done by washing the hydrocarbon stream with a caustic solution followed by a wash with water to remove the caustic.

Visbreaking is a mild thermal cracking process that reduces the viscosity of heavy fuel oils and reduces the amount of low-viscosity blending stocks that must be added to the heavy residuals to meet viscosity specifications of the specific heavy fuel oil. The amount of heavy fuel oil production by a refinery is reduced by 20–30 percent if a visbreaker is used. The refinery profitability is improved with visbreaker operation, because heavy fuel oils are low value products.

Small refineries usually produce the products in greatest demand, such as gasolines, jet and diesel fuels, and heavy fuel oils. Larger refineries produce a much broader slate of products because, with much higher feed rates, they can make economical volumes of small volume products. In addition, environmental requirements have made it much more difficult for small refineries because of the large capital investments required for the equipment to reduce impurities. Published economic studies indicate that refineries of less than 80,000 barrels per day of capacity do not produce sufficient income to justify the expensive equipment necessary for reformulated fuel production. Having fewer large refineries increases the transportation costs of getting the products to the necessary markets, but the increased size gives economies of scale. There are always fixed costs of labor and management that are independent of equipment size, and the incremental costs of higher charge rates are much less per unit volume than the total of fixed and operating costs. Depreciation costs per unit volume of throughput also decrease with the size of the equipment. In 1998, U.S. refineries operated at above 95 percent of rated charge capacity. This is much higher than it has been in the past. Even so, they have not been able to keep up with domestic demand, and imports of finished products have been increasing.

Operating costs vary a great deal from one refinery to another. Factors include the types of processes and equipment, the amount of the crudes that have to be cracked and alkylated to achieve the products desired, the degree of hydrogenation needed to meet product and environmental specifications, and the complexities and locations of the refineries. Energy is the single largest component of operating cost, so the costs of crude oils are major factors. For a simple hydroskimming refinery, the energy needed to process the crude oil can be as low as 2 percent of that in the crude oil, while for a very complex refinery with a large number of hydrogenation processes, it can be 8 percent or more of that in the crude oil.


The increasingly stringent environmental quality improvements for transportation fuels as specified by the EPA is putting constraints on present processing technologies. Process equipment needed for the newer technologies to meet future environmental restrictions is very costly and requires long lead times to design and build. Since the removal of low-cost lead compounds, used until the 1970s to increase the octanes of gasolines, refineries have been providing the replacement octane improvement needed by increasing the high-octane aromatic and olefin content of gasolines and also the amount of high-octane blending compounds containing oxygen (alcohols and ethers). The EPA is reducing the maximum aromatics and olefins content of reformulated gasolines for health and pollution reasons. There also is concern over the appearance of ethers in ground waters because of possible health effects, and it may be necessary to restrict their usage in gasolines. There is not enough ethanol available today to replace these components while providing the volumes of high-octane gasolines needed (over one million tons per day of gasolines used in the United States in 1998). Other ways must be used to provide the high octanes needed and to reduce degradation of the environment.

The United States is unique among the major countries in that supply and demand has determined price structures in the petroleum industry. Today, even though the products are much better than fifty years ago, the before-tax retail prices of gasolines, diesel fuels, and heating oils are much less on a constant-value dollar basis than they ever have been before. Even with the federal and state taxes included, the retail prices on a constant-value dollar basis are equivalent to those paid during the Depression years. In Europe, for example, taxes account for up to 80 percent of the costs of motor fuels that sell at retail for three to four times as much as they do in the United States.

U.S. production of crude oils has already peaked, and it is predicted that world production of crude oils will reach its maximum between 2010 and 2030. This does not mean that an adequate supply of crude oil will not be available, but supply and demand will create price structures that will make other sources of fuel more competitive. Global warming may also impose restrictions on the use of hydrocarbon fuels but, at the present time, there are no alternatives that do not require long lead times and very expensive and time consuming periods for building plants to produce the alternative fuels. If the alternatives cannot be marketed in existing petroleum facilities, it will also require that broad systems be built to market the fuels. It is difficult to conceive of the efforts that must be made to replace gasoline in the United States. Methanol has been mentioned as a replacement, but if the total annual production of methanol in the United States in 1998 was used in automobiles instead of gasoline, it would only be enough to operate them less than a week. During 1998, there were problems with electricity blackouts and restrictions of use in the United States without the added imposition of the power needed to charge batteries for replacement of gasolines in automobiles. conversion from petroleum fueled to electric powered vehicles will require the building of many more generating plants to supply the electricity necessary to meet transportation needs. When petroleum based fuels are replaced for transportation, several fuels probably will be used rather than one. Local deliveries, long distance deliveries, and travel will each use the most economical and environmentally friendly fuel.

James H. Gary

See also: Refining, History of.


Chang, Thi. (1998). "Distillation Capacities Hold Steady, More Mergers Planned." Oil & Gas Journal96(51):41–48.

Gary, J. H., and Handwerk, G. C. (1995). Petroleum Refining, Technology and Economics. New York: Marcel Dekker.

Radler, M. (1998). "1998 Worldwide Refining Survey." Oil & Gas Journal96(51):49–92.