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We thank the following for the use of their photographs and illustrations in this report.

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Contacts and Acknowledgments

This report was prepared by the Energy Information Administration (EIA) under the direction of Dr. John Cook, Director, Petroleum Division, Office of Oil and Gas. The authors

of this report are Dave Hinton, Nancy Masterson, Alice

Lippert, and Robert King of the Office of Oil and Gas.

This report is an update of a previous EIA publication, Petroleum An Energy Profile, DOE/EIA-0545(91) (August 1,

1991).

Questions about this report can be directed to the National

Energy Information Center, or at (202)586-8800. The EIA

statistics provided in this report were the most current data

available at time of publication. However, the user can update this report with the most current information by visiting

our website at http://www.eia.doe.gov/. See the end of each

chapter for the names of specific publications that are pertinent to each chapter.

In addition to the many data publications cited in this report,

EIA publishes many in-depth analyses of various aspects of

the petroleum industry. For a current list of these reports, see

our website mentioned above. Then select first “Petroleum”

and then select “Analysis” or “Feature Articles.”

The authors would like to acknowledge the contributions of

Charles Riner, Carolyn Mack, Dave Morehouse, Stefanie

Palumbo, Charles Shirkey, Mike Burdette, and Cynthia

McLaughlin of the Office of Oil and Gas in preparing this report, and Ann Whitfield of the National Energy Information

Center for the cover design.

ii Petroleum: An Energy Profile, 1999
Petroleum: An Energy Profile, 1999 iii

Contents

1. Introduction ..........................................................1

2. Petroleum Products ......................................................5

End-Use Sectors.......................................................6

3. Petroleum Resources and Reserves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

4. Exploration and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

5. Petroleum Refining . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25

LPG Sources and Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 31

Motor Gasoline Octane Enhancement . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 33

6. Transportation and Storage. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

Constructing Pipelines . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 35

The Strategic Petroleum Reserve. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 40

7. Imports and Exports . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 45

8. Petroleum Marketing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 53

Appendix A: District Descriptions and Maps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 61

Appendix B: Refinery Processes and Facilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 63

Glossary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 67

Tables

Table 3.1 Ten Largest Oil Fields in the United States as of January 1, 1999 . . . . . . . . . . . . . . . . . . . . . . . . . . 13

Table 5.1 U.S. Operable Refining Capacity as of January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Table 5.2 U.S. Operable Refining Downstream Capacity as of January 1 . . . . . . . . . . . . . . . . . . . . . . . . . . . 28

Table 5.3 U.S. Operable Production Capacity as of January 1. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 29

Table 5.4 Top Ten Petroleum Refining States as of January 1, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Table 6.1 U.S. Refinery Receipts of Crude Oil by Method of Transportation and Source, 1996 . . . . . . . . . . . . . . . 36

Table 7.1 Petroleum Product Imports by Type, Selected Years 1955-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Figures

Figure 1.1 Petroleum Products and Uses (1997 Percent Refinery Yield) ............................2

Figure 2.1 Estimated Petroleum Demand by End-Use Sector, 1997...............................5

Figure 2.2 Petroleum Demand by Product, 1981-1997 .....................................7

Figure 3.1 Petroleum Traps . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Figure 3.2 Petroleum Accumulation in Reservoir Rock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 11

Figure 3.3 U. S. Crude Oil Production versus Additions to Reserves, 1987-1997 . . . . . . . . . . . . . . . . . . . . . . . 12

Figure 3.4 World Crude Oil Resources (Billion Barrels) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 14

Figure 3.5 Estimated Reserves of Crude Oil by Nation, as of January 1, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . 15

Figure 4.1 World Crude Production in 1997 (Million Barrels per Day). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17

Figure 4.2 Onshore and Offshore U.S. Crude Oil Production, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Figure 4.3 Geographic Origins of U.S. Crude Production, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 18

Figure 4.4 ARotary Drilling System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 19

Figure 4.5 Average Cost of OilWell Drilling, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 20

Figure 4.6 Average Productivity of U.S. OilWells, 1965-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21

Figure 4.7 Secondary Recovery UsingWater Injection to Supplement Drive . . . . . . . . . . . . . . . . . . . . . . . . . 22

Figure 4.8 Enhanced Recovery Using Continuous Steam Injection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 23

Figure 5.1 Crude Oil Distillation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 26

Figure 5.2 Product Yield from a Barrel of Crude Oil, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 30

Figure 6.1 Petroleum Transportation by Mode of Travel, Selected Years 1975-1995 . . . . . . . . . . . . . . . . . . . . . 36

Figure 6.2 Inter-Regional Movement of Crude Oil and Petroleum Products byWater and Pipeline, 1997 . . . . . . . . . . . 37

Figure 6.3 Petroleum Pipelines in the United States as of December 31, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . 39

Figure 6.4 U.S. Crude Oil Stocks by Storage Facility, December 31, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . 41

Figure 6.5 Stocks of Major Petroleum Products by Storage Facility, December 31, 1997 . . . . . . . . . . . . . . . . . . . 41

Figure 6.6 U.S. Stocks of Crude Oil and Petroleum Products, End of Year 1949-1997 . . . . . . . . . . . . . . . . . . . . . 43
iv Petroleum: An Energy Profile, 1999

Figure 7.1 Petroleum Flow, 1997. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 46

Figure 7.2 U.S. Petroleum Imports by Source, 1980-1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 48

Figure 7.3 Sources of U.S. Crude Oil Imports, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 49

Figure 7.4 U.S. Petroleum Exports by Destination, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 50

Figure 7.5 Exports of Crude Oil and Petroleum Products, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 51

Figure 8.1 Critical Petroleum-Related Events and U.S. Crude Oil Refiner Acquisition Costs, 1970-1997. . . . . . . . . . . 54

Figure 8.2 Simplified Gasoline Market Structure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 57

Figure 8.3 Components of Retail Regular Gasoline Prices, 1997 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 58

Figure 8.4 Prices of Crude Oil and Retail Regular Motor Gasoline, 1970-1997 . . . . . . . . . . . . . . . . . . . . . . . . 59
1. Introduction

Petroleum has become so interwoven in the daily lives of

Americans over the past century that it now comprises an industry which accounts for about 40 percent of all energy consumed in the United States. Americans use petroleum,

directly or indirectly, in many applications including transportation fuel, light, heat, and for use in the manufacture of

consumer products. Daily per capita consumption of petroleum products in the United States averages nearly 3 gallons—more than one-fourth of the petroleum consumed

worldwide.

Petroleum is a complex mixture of liquid hydrocarbon—chemical compounds containing hydrogen and carbon—occurring naturally within the earth.1 Early use of

petroleum dates back many years. Man first became aware

of its existence when it was discovered oozing to the surface

from natural “seeps.” Native Americans used crude oil

skimmed from creeks and rivers as a medicinal ointment. In

the 1840’s and 1850’s, an enterprising Pennsylvanian bottled

and sold “Pennsylvania Rock Oil” to treat ailments such as

rheumatism, gout, and burns. By the time commercial production began in 1859, oil was demanded more for its ability

to produce light, and kerosene for use in lamps was the principal product. At the turn of the century, the advent of the

automobile shifted the emphasis to motor gasoline. In the

1930’s and 1940’s, a substantial market for heating oil

developed.

Because petroleum in its raw state has limited uses, further

processing of crude oil, via petroleum refining, is needed to

unlock the full potential of this resource. In the mid-1800’s,

the earliest refineries used a distillation process to produce

kerosene. Today’s refineries employ many processes from

simple distillation to the more complex “cracking” and “reforming” operations to convert crude oil into a wide array of

desired products. With approximately 20 percent of the

world’s crude oil distillation capacity and about 30 percent of

the more complex cracking and reforming capacity, the

United States leads the world in the production of petroleum

products. Moreover, motor gasoline alone accounts for about

one-half of all U.S. refinery production. (Figure 1.1).

Although petroleum provides many useful products, the

most notable are motor gasoline and heating fuel. Petroleum’s many uses in the transportation sector include fuel for

automobiles, trucks, agricultural and industrial machinery,

trains, ships, and aircraft. Petroleum is used to heat homes,

offices, and factories and is used to grow, process, package,

distribute, refrigerate, and cook food. Petroleum is also the

source of synthetic fabric for cloths as well as detergents and

Petroleum: An Energy Profile, 1999 1

Automobiles, trucks, and buses are fueled mostly by motor gasoline and diesel fuel.

1 Hydrocarbons are found under the earth’s surface in both gaseous and liquid form. “Natural gas” refers to hydrocarbons occurring in the gaseous

state; “petroleum” refers to liquid hydrocarbons: crude oil (Chapter 3), natural gas liquids recovered from natural gas in gas processing plants (Chapter

5), and the products they yield through refining (Chapter 5).
2 Petroleum: An Energy Profile, 1999

Note: Refinery yield represents the percent of finished product produced at U.S. refineries from input of crude oil and net

input of unfinished oils. Components do not add to 100 percent because of processing gain (an increase in volume that

occurs during refining).

Figure 1.1 Petroleum Products and Uses

(1997 Percent Refinery Yield)
dry cleaning solvent to clean them. Moreover, petroleum

provides a chemical base for cosmetics and pharmaceutical

products as well as for many plastic products from toys to

building materials.

The United States consumes more energy from petroleum

than from any other energy source. Petroleum provides

nearly two-thirds more energy than natural gas, nearly

three-fourths more energy than coal, and more than three

times the energy from all other energy resources. Although

the United States is one of the largest petroleum producers, it

actually consumes more than it produces, requiring net imports of crude oil to meet demand.

Growing U.S. petroleum product demand and declining domestic crude oil production have combined to make the

United States increasingly dependent on crude oil imports.

From its peak of 9.6 million barrels per day in 1970, domestic

crude oil production had declined by nearly one-third to 6.5

million barrels per day by 1997. During this same period, petroleum demand grew by one-fourth, from 14.7 million barrels per day in 1970, to over 18.6 million barrels per day by

1997. Consequently, net imports2 of crude oil and products

rose from 3.2 million barrels per day in 1970, to 9.2 million

barrels per day by 1997, causing U.S. dependence on petroleum net imports to grow from about one-fifth in 1970, to

nearly half by 1997.

While crude oil production is declining in the United States,

so are proved reserves of crude oil. The U.S. holds about a 2

percent share of the world’s crude oil reserves. As world reserves are depleted, the roles of Saudi Arabia and other Middle East suppliers are increasingly important in international

petroleum supply. This was dramatically illustrated by fears

of worldwide supply disruption following Iraq’s invasion of

Kuwait in August 1990.

A vast transportation network of tankers, barges, pipelines,

railways, and trucks moves crude oil from the field to refineries, where it is processed, and brings refined products to the

consumer. This complex system also links foreign suppliers

to domestic customers and provides access to foreign markets for products from U.S. refineries.

Storage facilities hold crude oil and refined products at various stages as they move through the system. Marine terminals receive crude oil as it is unloaded from tankers and hold

it until it is transported by pipeline or other means to the refinery for processing. When it reaches the refinery, it is

stored again until it can be processed. After processing, the

refined products go to bulk terminals where they are stored

until they are transferred to retail sales outlets and the final

consumer. Above-ground tanks, underground caverns and

tanks, and offshore storage are used to hold supplies of crude

oil and petroleum products as they move through the distribution system. The largest underground storage facilities are

part of the U.S. Strategic Petroleum Reserve, containing petroleum stocks maintained by the Federal Government for

use during periods of major supply disruptions.

The petroleum industry can be divided into two main sectors

that are largely functional in nature: the upstream sector that

includes exploration and production and the downstream

sector which includes refining, transportation, and marketing. The industry is highly integrated, with many firms involved in more than one sector. Large companies known as

“majors” are fully integrated and may own and operate establishments involved in all of these sectors. Smaller, nonintegrated companies often referred to as “independents”

generally specialize in one aspect, such as crude oil exploration and production or product marketing. The petroleum industry is international in scope, and it has a complex system

of markets where exchanges, long- and short-term sales contracts, and spot market and futures contracts are used to

transfer oil ownership as it passes from one sector to the next.

The following chapters discuss the role of petroleum products in our society and describe the workings of the U.S. petroleum supply network—from the petroleum resource base

through crude oil exploration and production, refining, transportation and storage, product marketing, and distribution.

Petroleum: An Energy Profile, 1999 3

For the most recent data on refinery yields and petroleum supply and demand, look for the current issues of

the Weekly Petroleum Status Report and the Petroleum Supply Monthly on the “Petroleum” page of EIA’s

website at http://www.eia.doe.gov/. For the most recent data and historical data on U.S. energy consumption, see the Monthly Energy Reviewand the Annual Energy Reviewon the “Historical” page of our website.

2 Gross imports minus exports.
2. Petroleum Products

We find petroleum products in every area of our lives. They

are easily recognized in the gasoline we use to fuel our cars

and the heating oil we use to warm our homes. Less obvious

are the uses of petroleum-based components of plastics,

medicines, food items, and a host of other products. Petroleum products fall into three major categories: fuels such as

motor gasoline and distillate fuel oil (diesel fuel); finished

nonfuel products such as solvents and lubricating oils; and

feedstocks for the petrochemical industry such as naphtha

and various refinery gases. Demand is greatest for products

in the fuels category, especially motor gasoline.

Petroleum products contribute about 40 percent of the energy

used in the United States. This is a larger share than any other

energy source including natural gas with a 25 percent share,

coal with about a 23 percent share, and the combination of

nuclear, hydroelectric, geothermal and other sources comprising the remaining 12 percent share.1 It is projected that

petroleum consumption in the United States will increase by

1.2 percent annually, reaching 24.7 million barrels per day by

the year 2020.2 Although petroleum consumption will continue to increase overall, its share of total energy use has

shrunk over the past several decades as a result of conservation efforts, fuel efficiency improvements, and growing use

of alternative sources of energy. While petroleum will undoubtedly remain the Nation’s leading energy source for

some time, the need to balance environmental, economic,

and energy security objectives has led policy-makers and

planners to seek means of diversifying the sources and reducing the role of this resource in our overall energy supply.3

Petroleum products, especially motor gasoline, distillate

(diesel) fuel, and jet fuel, provide virtually all of the energy

consumed in the transportation sector. Transportation is the

greatest single use of petroleum, accounting for an estimated

66 percent of all U.S. petroleum consumed in 1997 (Figure

2.1). The industrial sector is the second largest petroleum

consuming sector and accounts for about 26 percent of all petroleum consumption in the United States. Residential/Commercial and the electric utility sectors account for the

remaining 8 percent of petroleum consumption.4

Demand for petroleum products5 in the United States averaged 18.6 million barrels per day in 1997. This represents

about 3 gallons of petroleum each day for every person in the

country. By comparison, petroleum demand averaged about

2 gallons per person per day in the early 1950’s and nearly

3.6 gallons per person per day at its peak in 1978.

Price levels, economic growth trends, and weather conditions influence the demand for petroleum products. For example, oil prices affect a consumer’s willingness to use

petroleum instead of other fuels such as natural gas. High

prices relative to other fuels tend to encourage fuelswitching, especially at electric utilities, in industrial plants

having dual-fuel boilers, and in households that have woodburning stoves and electric heaters available.6 High prices

also provide incentive for individuals to adopt short-term

conservation measures, such as adjusting thermostats and reducing discretionary driving. High prices stimulate longterm measures as well, such as design changes that increase

fuel efficiency in automobiles, improved insulation in newly

constructed and existing buildings, and design changes in appliances to improve energy efficiency. Once in place, these

long-term conservation measures continue to affect fuel use

regardless of subsequent price fluctuations.

Low oil prices tend to stimulate demand. Demand also increases during periods of economic expansion, particularly

in the industrial and transportation sectors, as increases in the

production of goods bring corresponding increases in transportation of raw materials and deliveries of finished prodPetroleum: An Energy Profile, 1999 5

12.1

4.9

1.2

0.4

0

2

4

6

8

10

12

14

Transportation Industrial Residential/

Commercial

Electric Utility

Million Barrels per Day

Figure 2.1 Estimated Petroleum Demand by

End-Use Sector, 1997

Source: Energy Information Administration, Annual Energy

Review 1997, DOE/EIA-0384,Tables 5.12a and 5.12b.

1 Energy Information Administration, Monthly Energy Review, March 1999, DOE/EIA-0035(99/03), Table 1.4.

2 Energy Information Administration, Annual Energy Outlook 1999, DOE/EIA-0383(99), Table A11.

3 U.S. Department of Energy, National Energy Strategy, DOE/S-0124, April 1998, p. 16.

4 Energy Information Administration, Monthly Energy Review, April 1999, DOE/EIA-0035(99/04), Tables 1.4, 2.3, 2.4, 2.5 and 2.6.

5 Petroleum demand is measured when petroleum products become available, or “supplied” for domestic consumption as reported in the Petroleum

Supply Annual DOE/EIA-0340; “end use consumption” refers to estimates published in the State Energy Data Report, DOE/EIA-0214, and the Monthly

Energy Review, DOE/EIA-0035.

6 Energy Information Administration, Estimates of Short-Term Petroleum Fuel Switching Capability, DOE/EIA-0526, June 1989, p.iv.
ucts. Lower prices coupled with economic expansion

stimulated consumption during periods in the mid-1980’s

and mid-1990’s.

Weather extremes (winters that are colder than normal or

summers that are warmer than normal) also increase petroleum demand for heating or electricity generation for airconditioning purposes. Milder weather than normal tends to

reduce heating and air conditioning-related demand for petroleum fuels. Weather can also contribute to the seasonal

variations in demand for transportation fuels such as gasoline.

Petroleum demand illustrated the effects of these factors several times during the 1990’s. For instance, the Iraqi invasion

of Kuwait on August 2, 1990, caused petroleum demand to

sink to under 17 million barrels per day, its lowest level since

1987. The slowing economy and mild weather had weakened demand early in the year. Then, following the invasion,

prices climbed rapidly in response to uncertainty over future

supplies, with motor gasoline and jet fuel prices registering

dramatic increases. Shortly after the United Nations Security Council approved an embargo against oil exports from

Iraq and Kuwait, the Organization of Petroleum Exporting

Countries (OPEC) adopted a resolution allowing member

countries to exceed their production quotas to make up the

difference. As production increases from OPEC and other

countries began to offset the loss of Iraqi and Kuwaiti oil, petroleum prices subsided.

Petroleum Fuels

Fuel products account for nearly 9 out of every 10 barrels of

petroleum used in the United States. The leading fuel, motor

gasoline, consistently accounts for the largest share of petroleum demand (Figure 2.2). Demand for motor gasoline alone

accounts for more than 40 percent of the total demand for petroleum products. Other petroleum fuels include distillate

fuel oil (diesel fuel and heating oil), liquefied petroleum

gases (LPG’s)(including propane and butane), jet fuel, residual fuel oil, kerosene, aviation gasoline, and petroleum coke.

Motor gasoline is chiefly used to fuel automobiles and light

trucks for highway use. Smaller quantities are used for offhighway driving, boats, recreational vehicles, and various

farm and other equipment.

A number of factors influence the demand for motor gasoline. For example, rising gasoline prices in the 1970’s encouraged consumers to reduce discretionary driving and

stimulated consumer demand for smaller, more fuel efficient

automobiles. The Corporate Average Fuel Economy

(CAFE) Standards established by the Energy Policy and

Conservation Act of 1975 set mileage standards for new cars

that helped reduce gasoline demand even more as new, more

fuel efficient cars replaced older, less efficient cars. The effects of the market shift to smaller cars and the fuel efficiencies resulting from the CAFE standards continued to restrain

growth in gasoline demand through the 1980’s. However, by

the mid-1990’s, fuel efficiency growth slowed considerably

as low gasoline prices and rising disposable income spurred

consumers to buy less fuel efficient light trucks, vans, and

sport utility vehicles.

Environmental concerns have brought about a number of

changes in gasoline composition. To meet emission standards specified in the Clean Air Act of 1970, automobile

manufacturers introduced catalytic converters requiring unleaded fuel beginning in the 1975 model year. The Environmental Protection Agency (EPA) issued regulations in 1973

6 Petroleum: An Energy Profile, 1999

End-Use Sectors

The following are the major economic sectors to which consumption is allocated in this report.

Residential Sector. Private households that consume energy primarily for space heating, water heating, air conditioning,

refrigeration, cooking, and clothes drying.

Commercial Sector. Non-manufacturing or non-transportation business establishments, including hotels, motels,

restaurants, wholesale businesses, retail stores, laundries, and other service enterprises; health, social, and educational

institutions; religious and nonprofit organizations, and Federal, State, and local government institutions. Street lights,

pumps, bridges, and public services are included.

Industrial Sector. Manufacturing, construction, mining, agriculture, fishing, and forestry establishments.

Transportation Sector. Private and public vehicles that move people and commodities. Includes automobiles, trucks,

buses, motorcycles, railroads and railways (including streetcars), aircraft, ships, barges, and natural gas pipelines.

Electric Utility Sector. Privately and publicly owned establishments that generate, transmit, distribute or sell electricity

primarily for use by the public. Nonutility power producers are not included in the electric utility sector.
establishing requirements for the availability of unleaded fuels and, as the new cars entered the fleet, unleaded gasoline

began to displace leaded fuel. EPA continued the lead

phase-down, further restricting the lead content of motor

gasoline in 1982, 1985, and 1986. The Clean Air Act

Amendments of 1990 banned lead use entirely, effective

January 1, 1996.

As lead was eliminated, the use of other components, such as

butane, aromatics, alcohols, and ethers, to boost gasoline octane increased. Some of these additives like butane increase

the volatility, or evaporative tendency, of gasoline. As gasoline evaporates, contaminants are released into the atmosphere. EPA and several States have issued regulations to

restrict gasoline volatility in the summer months when the

problem is more severe. Federal regulations restricting gasoline volatility took effect in 1989. Several States and localities have also begun to require the use of other additives

termed “oxygenates” in gasoline to reduce carbon monoxide

emission levels during the wintertime. These restrictions

and proposals to amend the Clean Air Act encouraged the industry to develop and market new “reformulated” gasolines.

The Clean Air Act Amendments of 1990 set standards for reformulated gasoline and mandated its use in several U.S. cities beginning in 1995.

A number of “alternative” fuels have been developed for automotive use. Methanol (an alcohol produced from natural

gas, coal, or biomass) and ethanol (an alcohol produced from

biomass) are two alternative fuels that may be viewed as potential replacements for petroleum products or as additives

for use in present or future gasoline formulations.7 Compressed natural gas, electricity, propane, liquefied natural

gas, hydrogen, and solar energy are other transportation fuel

alternatives under consideration and in various stages of development.

Distillate fuel oil includes diesel oil, heating oils, and industrial oils. It is used to power diesel engines in buses, trucks,

trains, automobiles, and other machinery. It is also used to

heat residential and commercial buildings and to fire industrial and electric utility boilers. Specifications differ for heating oils and diesel fuels based primarily on the sulfur content

of each fuel.

Diesel fuel accounts for about three-fourths of refinery first

sales of distillate fuel oils.8 Most diesel fuel is used for transportation purposes: highway diesel fuel represents more than

half of distillate fuel sales. Residential heating, the next largest end-use category, represents about 12 percent of annual

distillate use, but is concentrated in the winter months.9

Petroleum: An Energy Profile, 1999 7

Figure 2.2 Petroleum Demand by Product, 1981-1997

1 Includes still gas, asphalt and road oil, petrochemical feedstocks, petroleum coke, lubricants, pentanes plus, kerosene, special naphtha, aviation

gasoline, waxes miscellaneous products, and crude oil.

Sources: Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1.

7 Methanol can be used alone as an alternative fuel, know as “M100." It can also be used as a component of the mixture of 85 percent methanol and

15 percent gasoline known as “M85.” Methanol is also used to produce methyl tertiary butyl ether (MTBE), an oxygenate used in reformulated

gasoline. Ethanol can also be used alone as a transportation fuel, but is generally blended with gasoline. It can also be used to produce ethyl tertiary

butyl ether (ETBE), another oxygenate.

8 Energy Information Administration, Petroleum Marketing Annual 1997, December 1998, DOE/EIA-0487(97) Table 50.

9 Energy Information Administration, Fuel Oil and Kerosene Sales 1997, DOE/EIA-0535(97), Table HL1.
Environmental concerns also extended to diesel fuel. The

Clean Air Act Amendments of 1990 mandated standards, effective October 1, 1993, for diesel fuels designated for

on-highway use to a maximum sulfur content of 0.05 percent

by weight.

Liquefied petroleum gases (LPG’s) rank third in usage

among petroleum products, behind motor gasoline and distillate fuel oil. LPG’s are used as inputs (feedstocks) for petrochemical production processes. This is their major nonfuel

use. LPG’s are also used as fuel for domestic heating and

cooking, farming operations, and as an alternative to gasoline for use in internal combustion engines.

Individual LPG products (see Glossary) have distinct uses.

For example, propane is widely used as a fuel in the residential, commercial, and industrial sectors. It is also important

as a petrochemical feedstock. Ethane is used primarily as a

petrochemical feedstock. Butane is used as a gasoline blending component, although volatility regulations for gasoline

have limited its use for this purpose (see Chapter 5). Butane

also has many domestic and industrial uses.

Most jet fuel is a kerosene-based fuel primarily used in commercial airlines. It requires a higher temperature to ignite

and is safer for commercial use than naphtha-based fuel.

Naphtha jet fuel meets the specifications required for certain

military aircraft. It has a lower freezing point than commercial fuel and a lower flash (ignition) point. However, from

October 1, 1993, through 1995, the U.S. military essentially

converted most of its jet fleet from naphtha-type jet fuel to

kerosene-type jet fuel.

Kerosene-type jet fuel is sometimes blended into heating oil

and diesel fuel during periods of extreme cold weather. This

is done to help alleviate viscosity (thickness), handling and

performance problems associated with cold weather.

Electric utilities use residual fuel to generate electricity. Although this sector uses relatively little petroleum compared

with the transportation and industrial sectors, the electric

utility sector depends on petroleum for about 5 percent of its

total energy requirements. Much of the surplus capacity for

electricity generation is oil-fired, so petroleum use by utilities is expected to increase along with electricity demand.

Residual fuel oil is also used as bunker fuel (fuel for ships),

industrial boiler fuel, and heating fuel in some commercial

buildings.

Kerosene is used for residential and commercial space heating. It is also used in water heaters, as a cooking fuel, and in

lamps. Kerosene falls within the light distillate range of refinery output that includes some diesel fuel, jet fuel, and

other light fuel oils.

Petroleum coke can be used as a relatively low-ash solid

fuel for power plants and industrial use (marketable coke) if

its sulfur content is low enough, or used in nonfuel applications (catalyst coke), such as in refinery operations.

Nonfuel Products

Nonfuel use of petroleum is small compared with fuel use,

but petroleum products account for about 89 percent of the

Nation’s total energy consumption for nonfuel uses. There

are many nonfuel uses for petroleum, including various specialized products for use in the textile, metallurgical, electrical, and other industries. A partial list of nonfuel uses for

petroleum includes:

• Solvents such as those used in paints, lacquers, and

printing inks

• Lubricating oils and greases for automobile engines

and other machinery

• Petroleum (or paraffin) wax used in candy making,

packaging, candles, matches, and polishes

• Petrolatum (petroleum jelly)sometimes blended with

paraffin wax in medical products and toiletries

• Asphalt used to pave roads and airfields, to surface canals and reservoirs, and to make roofing materials and

floor coverings

• Petroleum coke used as a raw material for many carbon

and graphite products, including furnace electrodes and

liners, and the anodes used in the production of aluminum.

• Petroleum Feedstocks used as chemical feedstock derived from petroleum principally for the manufacture of

chemicals, synthetic rubber, and a variety of plastics.

Petrochemical Feedstocks

Petroleum feedstocks have been used in the commercial production of petrochemicals since the 1920’s. Petrochemical

feedstocks are converted to basic chemical building blocks

and intermediates used to produce plastics, synthetic rubber,

synthetic fibers, drugs, and detergents. Naphtha, one of the

basic feedstocks, is a liquid obtained from the refining of

crude oil.

Petrochemical feedstocks also include products recovered

from natural gas, and refinery gases (ethane, propane, and

butane). Still other feedstocks include ethylene, propylene,

normal- and iso-butylenes, butadiene, and aromatics such as

benzene, toluene, and xylene. These feedstocks are pro8 Petroleum: An Energy Profile, 1999
duced by processing products such as ethane (separated from

natural gas), distillates, naphthas, and heavier oils.

Industry data show that the chemical industry uses nearly 1.5

million barrels per day of natural gas liquids and liquefied refinery gases as petrochemical feedstocks and plant fuel.10

Demand for textiles, explosives, elastomers, plastics, drugs,

and synthetic rubber during World War II increased the petrochemical use of refinery gases. Gas byproducts from the

production of gasoline are an important source of many feedstocks.

Petroleum: An Energy Profile, 1999 9

For the most recent data on petroleum supply and demand, look for the current issues of the Weekly Petroleum Status Report and the Petroleum Supply Monthly on the “Petroleum” page of EIA’s website at

http://www.eia.doe.gov/ . Sales volumes for petroleum products are in the Petroleum Marketing Monthly,

also on the “Petroleum” page. For the most recent data and historical data on U.S. energy consumption by

fuel type and end-use sector, see the current issues of the Monthly Energy Review and the Annual Energy

Review on the “Historical” page of our website.

10 American Petroleum Institute, 1996, Sales of Natural Gas Liquids and Liquefied Refinery Gases, October 1997, Table 1.
3. Petroleum Resources and Reserves

The most widely accepted explanation of how oil was

formed within the earth is the biological, or organic, theory

which asserts that hydrocarbons were created from the remains of once-living organisms.1 The biological process is

believed to have begun millions of years ago when the remains of microscopic marine plants and animals settled at the

bottom of bodies of water. As time passed, more layers of remains and inorganic materials, such as sand and clay-rich

mud, settled on top. Pressure, dehydration and cementation

compacted the inorganic particles, forming them into sedimentary rock. Temperatures rose as a result of the geothermal gradient within the earth. The organic material –

composed of carbon, hydrogen, oxygen, and other elements

– reacted to the heat, pressure, and bacteria action. The original chemical bonds were broken and the elements were reformed into hydrocarbons and other compounds, mainly

water and carbon dioxide.

Over time, oil migrated from the formations where it was created (the source rocks) to more porous rock. Migration, generally upward, stops only when oil finally seeps out of the

ground or encounters a trap inside the earth.2 A trap is a barrier to the upward movement of oil, often a rock formation so

dense that oil cannot penetrate it. Anticlines, faults, and salt

domes are common trapping structures (Figure 3.1). Movements or shifts inside the earth can cause rock layers to fold

upward forming an anticline or to break along a fault line. An

impenetrable rock layer lying over an oil-bearing layer can

trap oil inside the hill-shaped structure of an anticline. Along

a fault line, a porous oil-bearing layer may be shifted next to a

nonpourous layer, trapping oil there. A salt dome is formed

by the upward movement of a large underground deposit of

solid salt remaining from ancient shallow seas. Because oil

cannot penetrate salt, it is often found trapped in the sediments layers tilted up around the sides of salt domes. In fact,

early drillers who sank wells near salt domes to extract brine

for preserving meat and other foods were often dismayed to

find oil coming up with and contaminating their brine.

The rock formation where oil collects beneath a trap is

known as a reservoir. Oil, usually together with natural gas

and salt water, resides in tiny pore spaces between the grains,

or in the fractures, of the reservoir rock (Figure 3.2). One or

more reservoirs related to the same geological feature are

known as a field. The most common types of rock found to

contain oil are sandstone, limestone, and dolomite.

Each reservoir has unique characteristics which determine

how much of the oil residing there can ultimately be extracted and what techniques are required to bring the oil up

Petroleum: An Energy Profile, 1999 11

Figure 3.1 Petroleum Traps

Source: Energy Information Administration, Office of Oil and Gas.

Figure 3.2 Petroleum Accumulation in Reservoir

Rock

Source: Energy Information Administration, Office of Oil and Gas.

1 A few scientists believe that hydrocarbons were generated during the earth’s creation, from the same inorganic materials which formed the earth, and

have been slowly seeping out of the earth’s center since. Acceptance of this “abiogenic theory” of petroleum formation, however, is not widespread.

2 Slippery Rock Creek, Pennsylvania was named after a rocky area of a creek into which oil naturally seeped. Early oil fields were often found by

drilling near existing oil seeps.
from the reservoir. Two of the most important characteristics are porosity and permeability. Porosity refers to the

amount of pore space in the rock and permeability refers to

the ability of a liquid to flow through the rock from pore to

pore, pore to fracture, or fracture to fracture. A formation

with high porosity can hold more oil in a given volume of

rock. If a reservoir has many large connections between the

pore spaces, it has good permeability.

The total quantity of oil which is trapped within the boundaries of a reservoir or field make up its total oil resources. Total world oil resources include all the oil ever generated

inside the earth and trapped there. The amount of total resources in the world, or in any particular field, is uncertain.

Estimates of oil resources, by field and by nation, are routinely made using information from geologists and engineers

who measure the porosity and permeability of rock formations, construct geological maps, estimate the extent and

thickness of formations suspected or known to contain oil,

and compile many other types of data. These estimates are

continually revised as more knowledge becomes available.

A portion of the world’s oil resources will never be recovered

from the earth because of physical, technological, or economic constraints. For example, the recovery of oil from

some reservoirs that are very difficult to reach or that contain

extremely small amounts of oil, would consume more energy

than the recovered oil would ultimately yield. Also, even

though recovery techniques have improved over time, current methods do not enable producers to extract all the oil

from developed fields. Of those resources which are recoverable, only a portion have already been discovered; others

are thought to exist in favorable geologic settings but are, as

yet, undiscovered. Resources which have already been discovered and produced are referred to as cumulative production. Recoverable resources which remain to be produced

are referred to as reserves. Those reserves which are expected to be recoverable in the future under existing technological and economic conditions are known as proved

reserves.

When new fields or reservoirs containing oil are discovered

or when known reservoirs are extended by drilling additional

wells, proved reserves increase. When oil is removed from a

reservoir by production, proved reserves decrease. If new information on a reservoir’s characteristics becomes available

and indicates there is more or less oil trapped there than originally thought, proved reserves estimates are revised up or

down accordingly. Because of the way proved reserves are

defined, changes in the economy, especially the price of

crude oil or operating conditions or technology can also increase or decrease proved reserves. Proved ultimate recovery is the sum of the estimate of proved reserves at a specific

time and cumulative production up to that time.

U.S. and World Reserves

A major increase in U.S. proved reserves occurred in 1970

when newly discovered oil in Alaska was added to the estimates of proved reserves.3 Since then, U.S. proved reserves

have declined overall as there have been few major oil discoveries and the rate of production has generally exceeded

12 Petroleum: An Energy Profile, 1999

0.0

1.0

2.0

3.0

4.0

1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997

Billion Barrels

Reserve Additions

Production

Figure 3.3 U. S. Crude Oil Production versus Additions to Reserves, 1987-1997

Note: Production estimates are based on data reported on Form EIA-23 and do not include estimates for lease condensate. Thus, they differ from the

crude oil production data contained in the Petroleum Supply Annual.

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report,

DOE/EIA-0216(97).

3 Several years often elapse between the time a field is discovered and the time its resources are determined to be proved reserves.
the rate of additions to reserves (Figure 3.3). For the most

part, revisions to earlier proved reserves estimates have contributed more than discoveries to reserve additions; that is,

drilling in existing fields plus technological advances are

finding more oil than wildcat (new field) wells are. While

crude oil discoveries increased 33 percent in 1997 over the

previous year, revisions to earlier estimates continue to be

the most significant factor in moderating the decline in reserves. From 1977 through 1995 approximately 93 percent

of the additions to U.S. proved reserves of crude oil were due

to proved ultimate recovery appreciation rather than to the

discovery of new oil fields.4

As of December 31, 1997, it was estimated that the United

States had 22.5 billion barrels of proved crude oil reserves

and 8.0 billion barrels of proved natural gas liquids reserves.

Most of these are located in Texas, Alaska, and California.

Texas had an estimated 5.7 billion barrels and Alaska had an

estimated 5.2 billion barrels of crude oil proved reserves at

the end of 1997, while California had an estimated 3.8 billion

barrels. Offshore areas of California, Texas, and Louisiana

also contain a large share of proved reserves. Most of the offshore proved crude oil reserves, 2.7 billion barrels of the 3.5

billion-barrel total in 1997, were located in federally controlled waters of the Outer Continental Shelf.

The largest oil field discovered in the United States to date is

the Prudhoe Bay Field in northern Alaska. Its ultimately recoverable resources (cumulative production plus remaining

proved reserves) are estimated to be 13 billion barrels of

crude oil (Table 3.1). As of January 1, 1999, its remaining

proved reserves were estimated to be 3.3 billion barrels. The

second largest field in the United States, East Texas, was discovered over 60 years ago; much of its oil has already been

produced. Originally estimated to hold 6 billion barrels of

recoverable crude oil in total, it is now estimated to have less

than 1 billion barrels of remaining proved reserves.

The United States has already developed many of its oil resources. There are other areas of the world where many resources remain to be developed (Figure 3.4). Estimates

indicate that the United States has only about 3 percent of the

world’s remaining recoverable crude oil. Estimates of

proved world crude oil reserves at the beginning of 1998

vary between 974 and 1,020 billion barrels.5

Most of the world’s reserves are located in the Middle East.

Saudi Arabia has more crude oil reserves that any other nation. About two-thirds of the world’s proved reserves of

crude oil are located in countries which belong to the Organization of Petroleum Exporting Countries (OPEC) (See Glossary.) (Figure 3.5).

Although there are relatively few giant oil fields in the world, they acPetroleum: An Energy Profile, 1999 13

Oil Field Location Year

Discovered

Cumulative

Production

Estimated

Remaining

Reserves

Estimated

Recoverable

Resources

(billion barrels)

Prudhoe Bay Alaska 1968 9.7 3.3 13.0

East Texas Texas 1930 5.3 (s) 5.4

Wilmington California 1932 2.5 0.3 2.8

Midway-Sunset California 1894 2.4 0.3 2.7

Kuparuk River Alaska 1969 1.6 1.0 2.6

Wasson Texas 1936 2.0 0.1 2.1

Kern River California 1899 1.7 0.4 2.1

Yates Texas 1926 1.4 0.6 2.0

Panhandle Texas 1921 1.5 (s) 1.5

Elk Hills California 1911 1.1 0.3 1.4

Table 3.1 Ten Largest Oil Fields in the United States1 as of January 1, 1999

1

By size of total recoverable resources.

(s) = less than 100 million barrels.

Note: Total may not equal sum of components due to independent rounding.

Source: PennWell Publishing Company, Oil & Gas Journal, January 25, 1999, pp. 76-77.

4 Energy Information Administration, Petroleum Supply Monthly, July 1997, DOE/EIA-0109(97/07), “The Intricate Puzzle of Oil and Gas Reserves

Growth,”page xxiii-xxiv, errata.

5 Energy Information Administration, International Energy Annual 1997, DOE/EIA-0219(96)(January 1998), Table 8.1, including estimates from

World Oil (August 1997) and Oil & Gas Journal (December 1996).
count for most of the world’s reserves.6 Saudi Arabia has the

world’s largest known oil field, the Ghawar Field, which was

discovered in 1948. Ultimate resources of this field are estimated at 123 billion barrels of recoverable crude oil, of

which 48.9 billion barrels have already been produced.7 As

of 1984, there were 265 world-scale “giant” oil fields, 18 of

which contained 10 billion barrels or more of recoverable resources.8

Because most areas of the United States have already been thoroughly

explored,thelikelihood of findingmajor new discoveriesiswaning. At

theend of 1997, however,theUnitedStates had 3.2 billion barrels ofindicated additional crude oil reserves, which may be reclassified as

proved reserves in the future. These reserves, located mostly in central

California, western Texas, and Alaska are known crude oil reserves

which are believed to be recoverable using current technology, but for

which the potential for economic recovery under current conditions is

uncertain. Theywillbeaddedtocrudeoil reservesifandwhen productiontechniquesareappliedandtheyprovetobeeconomicallypractical.

Estimates havealso beenmade of undiscovered resourcesintheUnited

States. The existence and recoverability ofthese resourcesismuchless

certain than that of proved reserves. It is estimated that in 1995, the

UnitedStateshad77.9billionbarrelsofundiscoveredtechnically recoverable crude oil.9 About 60 percent of these undiscovered resources

were estimated for areas located offshore on the Outer Continental

Shelf.

14 Petroleum: An Energy Profile, 1999

184 21

31

213

157

90

66

35

676

128

22

68

19

84

18

5

United

States

Mexico, Central

America, &

South America

Canada

Western

Europe

Middle

East

Eastern Europe,

Former U.S.S.R.,

China, & Vietnam

Other Eastern

Hemisphere

Africa

Cumulative Production 1859-1996

Reserves as of January 1, 1997

Figure 3.4 World Crude Oil Resources (Billion Barrels)

Sources: Cumulative Production 1859-1984: The British Petroleum Company, BP Statistical Review of World Energy, June 1985; Production:

1985-1996: Energy Information Administration, International Energy Annual 1996, and previous reports, Table 2.2; Reserves: Energy Information

Administration, International Energy Annual 1996, Table 8.1.

6 In the United States, the term “giant” usually refers to a field with total recoverable oil resources of 100 million barrels or more and a “supergiant”

field is one that contains at least 500 million barrels. On a worldwide basis, however, the term “giant” usually refers to fields with recoverable resources

of 500 million barrels or more.

7 Petroconsultants, Reserves and Production Database, Geneva.

8 Tiratsoo, E.,N., Oilfields of the World, 3rd edition (Houston, Texas: Gulf Publishing Company, 1984), p. 23

9 US Department of Interior, Minerals Management Service and U.S. Geological Survey, Estimates of Undiscovered Recoverable Conventional Oil and

Gas Resources in the United States – A Part of the Nation’s Energy Endowment (Washington, DC. 1989)
Petroleum: An Energy Profile, 1999 15

For more information on petroleum resources and reserves, look for the current issue of U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves annual report, and for the most recent data on U.S. crude oil production, see the Petroleum Supply Annual, Volume 1, both on the “Petroleum” page of EIA’s website at

http://www.eia.doe.gov/. World crude oil production and reserves can be found in the International Energy

Annual on the “International” page of our website.

0 50 100 150 200 250 300

Other

United States

Mexico

Former U.S.S.R.

Other

Venezuela

Iran

Kuwait

United Arab Emirates

Iraq

Saudi Arabia

Billion Barrels

OPEC

NonOPEC

Petroleum is produced from reservoirs such as this one located at Lost Hills, California.

Figure 3.5 Estimated Reserves of Crude Oil by Nation, as of January 1, 1997

Source: Energy Information Administration, U.S. Crude Oil, Natural Gas, and Natural Gas Liquids Reserves 1997 Annual Report,

DOE/EIA-0216(97).
4. Exploration and Production

The process of removing crude oil from beneath the earth’s

surface begins with exploration to find areas where petroleum deposits are most likely to exist. Drilling and extraction, comprise the production phase of oil recovery.

Commercial production of petroleum in the United States began in 1859 when “Colonel” Edwin Drake drew oil from a

well in Titusville, Pennsylvania, the first modern well drilled

exclusively for that purpose. Production increased steadily

throughout the rest of the century, remaining centered around

Pennsylvania, Ohio, and West Virginia. Then in 1901, the

Spindletop well in Texas met with success, gushing oil at a

rate never experienced before, and the “rush” was on. From

1901 to 1910, the rate of oil production in the United States

more than tripled. By 1929, the United States, led by Texas,

California, and Oklahoma, was producing over 1 billion barrels of crude oil a year. In 1948, production reached 2 billion

barrels and increased almost every year thereafter until it

reached its peak of 3.5 billion barrels in 1970.1

Today, U.S. production is influenced by several factors including reserve availability, legal accessibility of prospective drilling sites, effects of regulations covering

environmental and occupational health, drilling and recovery technology, and crude oil prices. Declining reserves and

the declining average productivity of oil wells (number of

barrels produced per day) are lowering the amount of production. As more oil is removed from reservoirs, less remains for later production; what does remain is more

difficult and expensive to recover (unless new technology

lowers the cost beyond the rise in difficulty). Many U.S. reservoirs have already been depleted of their easily recoverable reserves. Improving technologies for enhanced oil

recovery could enable more production from these reservoirs

in the future, but at the present time these methods are still

very expensive, making their use unprofitable in many cases.

U.S. production levels are also greatly influenced by crude

oil prices. When the price of oil is low, it becomes less profitable to explore for and produce oil, and production usually

declines. The annual average number of rigs drilling for oil

has dropped from 532 in 1990 to 264 in 1998.2 Existing wells

which need costly maintenance are often shut in temporarily

during periods of low prices. A substantial number of those

shut-in wells will be permanently plugged as prices continue

to fall. In 1986, a major drop in the price of crude oil caused

production to decline by about 3 percent to 8.7 million barrels per day. Although prices fluctuated between 1987 and

Petroleum: An Energy Profile, 1999 17

Saudi Arabia 8.6

Iran 3.7

Venezuela 3.3

Nigeria 2.3

Other OPEC 8.1

OPEC 28.4

Other 15.1

Eastern

Europe &

former

U.S.S.R. 7.1

United States 6.5

China 3.2

Norway 3.1

Mexico 3.0

United Arab Emirates 2.3

World Production 66.4

Figure 4.1 World Crude Production in 1997

(Million Barrels per Day)

Note: Totals may not equal sum of components due to independent rounding.

Source: United States: Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1. Rest of world: Energy

Information Administration, International Energy Annual 1997, DOE/EIA-0219(97).

1 American Petroleum Institute, Basic Petroleum Data Book, Vol. 11, No.1 (Washington, DC, January 1991), Section 4.

2 Baker-Hughes, Inc. Houston, Texas, weekly phone recording.
1990, they remained well below the levels of the early 1980’s

and production continued to decline, falling to 7.4 million

barrels per day by 1990. Higher prices in the last half of 1990

boosted domestic crude oil production slightly in 1991, but

were unable to reverse the 6-year downtrend that saw domestic production decline by 1997 to its lowest level since 1954.

This downward trend is expected to continue at a rate influenced by the world oil price.

Saudi Arabia, the United States, and Russia are the largest

petroleum producing nations in the world. The United States

accounted for about 10 percent of the total world production

of crude oil in 1997 (Figure 4.1). Saudi Arabia produced

about 13 percent of the world total and is currently the

world’s largest producing nation, while Russia accounted for

about 9 percent of the world total in 1997. Crude oil production in Russia, falling since 1988 with the dissolution of the

Soviet Union, showed a small increase in 1997.

Offshore areas contributed nearly 25 percent of U.S. crude

oil production in 1997 at a rate of 1.6 million barrels per day

(Figure 4.2), the highest level since 1973. The increased

share of offshore production in 1997 reflects the reduced production in large onshore Alaska fields. The giant oil fields in

Alaska were discovered in the late 1960’s, but significant

production did not begin until the Trans-Alaska Pipeline

System was completed in 1977 (Figure 4.3). Alaskan production began to decline in 1989, largely because of the natural decline of the Prudhoe Bay field. In 1997, Texas was the

leading U.S. producing State, accounting for 23 percent of

U.S. crude oil production. Alaska was the second largest

with 20 percent, followed by California with 12 percent,

Louisiana with 6 percent, Oklahoma with 4 percent and Wyoming with 3 percent. These six States, together with Federal

offshore areas, accounted for 87 percent of the crude oil produced in the United States during 1997.

Exploration

Before the turn of the century, prospectors relied on their

senses, some simple instruments like divining rods, and

mostly luck to help them find oil. They often drilled in areas

where oil was seen seeping from the earth, or where surface

features resembled those around earlier oil discoveries.

Around 1900, oil seekers began to employ scientific techniques. Geologists, and later geophysicists, began to study

the Earth’s structure, looking for areas of sedimentary rock

and for irregularities in rock formations which could cut off

migrating oil and cause it to accumulate in reservoirs. Today,

explorers measure such things as magnetic fields and differences in the pull of gravity to help identify promising formations, but the most widely used technique is the seismic

survey.

During a seismic survey, the ground is vibrated to create

sound waves. Geophones (ultrasensitive microphones) set

out along the ground monitor the sound waves and measure

the time it takes for them to reflect from subsurface rock formations. Maps of the underground structure can be produced

from these measurements.

Dynamite explosions used to be the primary means of producing vibrations, but today specially designed trucks which

vibrate the ground with heavy weights are often used instead.

The trucks are safer and less harmful to the environment.

Computers filter out excess noise and otherwise aid the interpretation of seismic data. They also facilitate the production

of maps and cross-sections: using new techniques, two- or

three-dimensional images of the underground structure can

be created.

Seismic surveys are also conducted offshore where

hydrophones towed behind a seismic ship perform the same

function as geophones. The sound waves are generally created by air or gas guns which are also towed by the ship. Measuring reflection times is more difficult offshore because

18 Petroleum: An Energy Profile, 1999

0

2

4

6

8

10

1970 1975 1980 1985 1990 1995

Million Barrels per Day

Total

Onshore

Offshore

Figure 4.2 Onshore and Offshore U.S. Crude Oil

Production, 1970-1997

Source: 1970-1996: Energy Information Administration, Annual

Energy Review 1997, DOE/EIA-0384, 1997: Energy Information

Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97).

0

2

4

6

8

10

1970 1975 1980 1985 1990 1995

Million Barrels per Day (Cumulative)

Alaska

Lower 48 States

1977: Trans-Alaska Pipeline Completed

Total

Figure 4.3 Geographic Origins of U.S. Crude

Production, 1970-1997

Source: 1970-1996: Energy Information Administration, Annual

Energy Review 1997 DOE/EIA-0384(97), 1997: Energy Information

Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97).
vibrations pass through the water before reaching the earth.

Computer programs are used to distinguish significant reflections from unwanted noise and to determine structure locations. While seismic surveys for many years produced

two-dimensional charts along the line of the survey,

three-dimensional (3D) surveys are now commonplace in

both exploration and development of oil and gas fields. The

image from a 3D survey can help with placement of future oil

wells and is especially useful if a horizontal well is planned.

Two or more 3D seismic surveys conducted over the same

area are known as four-dimensional (4D) seismic, with time

as the fourth dimension. A 4D survey can show the movement of distinct fluids in a reservoir, allowing modification

of drilling and production operations to capture more oil.

Seismic exploration activity peaked in 1981 in response to

high crude oil prices which gave companies incentives to

search for more oil reserves. By contrast, when crude oil

prices fell in 1986, the number of seismic crews working fell

almost 50 percent from the level of the previous year.

Other methods of exploring from remote positions, including the recording of magnetic and gravity measurements

from airplanes and the use of satellite images to locate areas

are continually being developed. Although scientific data

can greatly improve the chances of finding oil in a particular

area, there is no way to be sure oil exists, or that enough oil

will be found to make its recovery profitable, without actually drilling a well.

Drilling

Before there was a great demand for petroleum, people dug

and drilled wells into the earth to reach sources of water and

salt. Oil well drillers adopted techniques from these earlier

drillers, and added some innovations of their own. One early

drilling rig, consisting of a springing pole attached to a rope

with a heavy bit at the end, was operated by a person’s foot,

and an early rotating drill was operated by mule power. Colonel Drake’s 1859 well was drilled using a cable-tool rig, a device which pounds a chisel-like bit into the ground. The rig

was powered by a steam engine. The Spindletop well in

Texas, in addition to being America’s first gusher, was notable as one of the earliest successful uses of a modern rotary

drilling system (Figure 4.4). A rotary rig uses a rotating bit

which drills a hole into the ground. Today, some wells are

still drilled with cable-tool rigs, but use of the cable-tool rig

has been far surpassed by the rotary rig. Coiled tubing drilling using a continuous small pipe (2 to 4 inches) with a

downhole hydraulically-driven mud turbine motor to power

the rotating drill bit has been used in an increasing number of

wells since 1990.

A rotary-rig bit cuts and crushes rock as it descends. The bit is

attached to the bottom of a long string of steel pipe. At the top

of the string is the kelly, a square or hexagonal section of

pipe that is inserted through a steel disk known as the rotary

table. The rotary table has a square or hexagonal hole in the

center to receive the kelly and is geared to a motor at its perimeter. The table turns, rotating the whole string of kelly,

drill pipe, and bit.

As a well gets deeper, more pipe is added to the drill string

below the kelly. Support for the heavy drill string is provided by a tall steel structure known as a derrick. The derrick

contains heavy equipment which can lift the entire drill

string from the well and then return it, an operation called

tripping that must be done to change the bit (drill bits wear

out in use, also certain rock types are drilled more efficiently

with specialized bits), make repairs to the downhole

drillstring, and test the well. During a complete trip, all of the

drill pipe is removed from the hole, unscrewed into 90 foot

sections, and stacked, and then the whole process is done

again in reverse.

Drilling mud, usually a mixture of minerals and water or oil,

is critical to drilling. Mud is pumped down the well through

the center of the drill string and drill bit and then circulated

back to the top, pushing the pieces of rock which have been

cut by the bit up and out of the hole. The mud also keeps the

bit cool, coats the sides of the well to keep soft rock formaPetroleum: An Energy Profile, 1999 19

Drill Pipe

Drilling Mud

Casing

Bit

Derrick

Hoisting Equipmentincluding Line, Travelling Block,

Swivel, and Hook

Mud Hose

Drawworks and Engines

Mud Pump

Mud Pit

Blowout

Preventors

Kelly

Rotary Table

Figure 4.4 A Rotary Drilling System

Source: Energy Information Administration, Office of Oil and Gas.
tions from caving in, and controls pressure from fluids in the

formation to prevent blowouts (sudden explosive releases of

gas or oil). Properties such as the weight and thickness of the

mud are specifically designed for each well. Some geologic

formations allow the use of air as a drilling “mud”, especially

where clay minerals in the rocks show a tendency to swell

when wetted with water, thereby plugging a reservoir’s pore

spaces.

Most wells are lined with steel pipe, known as well casing,

which is cemented into place. It prevents collapse of the

sidewalls of the well and prevents the unwanted movement

of fluids between rock layers. During drilling operations, a

set of strong valves known as blowout preventers is affixed

to the top of the surface casing beneath the rotary table. If a

high pressure zone of oil or gas is encountered while drilling,

these valves can be closed to prevent a blowout. When the

well is producing, the top of the casing serves as a place to

connect the surface equipment. Production tubing is inserted

into most wells as part of the completion process. It can

allow simultaneous production from more than one reservoir

at a time.

In onshore operations, a rig usually drills a single vertical

well. Offshore rigs most often drill several wells from one location using directional drilling, where the angle of a well is

diverted from vertical. Directional drilling is also used onshore to reach under obstacles such as riverbeds and lakes. In

recent years, there has been an increase in horizontal drilling activity. Horizontal drilling can reach difficult areas of

thin reservoirs, and can also be used to increase the area of a

reservoir that can be contacted by one well, substantially increasing the rate of production. Horizontal wells are usually

drilled off of vertical wells as they approach the oil-rich

zone. Existing wells have had horizontal sections or laterals

added in the producing zone using coiled tubing drilling

units. In 1997, the average cost for drilling oil wells horizontally was 24 percent higher than the average cost for oil wells

not drilled horizontally.3

Offshore drilling methods are similar to those used onshore,

but the equipment must be adapted to meet the harsh marine

conditions. A special structure is needed to support the derrick and other drilling equipment. This structure may rest on

the sea floor or float in or on the water. The type of structure

chosen usually depends on the water depth, weather, and sea

conditions in the area where drilling will occur.

The major types of offshore drilling rigs are: barges, fixed

platforms, jack-ups, semi-submersibles, and drill ships.

Barges are used in inland waters while the others are usually

used off the coast. Fixed steel platforms rest on the sea floor,

usually in shallow water, and they are seldom moved once

they have been put in place. Jack-ups have legs which can be

raised up and down in a manner similar to the action of an

automobile jack. With the legs raised they can be moved to a

location, then the legs can be jacked down to the sea floor.

The base of a semi-submersible rig actually floats below the

surface of the water. Its position-holding anchors are supplemented by the computer-controlled motors of the vessel.

Semi-submersibles are very stable in bad weather conditions

and yet can be moved from place to place. Drill ships, which

have been adapted for drilling by cutting out a vertical opening in the middle of the ship, have been used in the deepest

waters. These ships use anchors or motors to hold them

steady over the well.

Because of the difficulty of transporting drilling crews to offshore locations, offshore rigs provide living quarters for the

workers, with facilities for sleeping, eating, entertainment,

and other activities not usually provided at onshore drill

sites. Helicopters are now the primary means of transportation between land and rig. Therefore, one prominent feature

of the offshore rig is a helipad. In case of hurricanes in the

Gulf of Mexico, crews must secure the production platforms

and leave well ahead of the possible arrival of a hurricane.

Offshore wells are much more expensive to drill than onshore wells (Figure 4.5). In 1997, the average onshore oil

well cost $74.23 per foot drilled, while the average offshore

well cost $526.37 per foot.4 Drilling costs are also influenced by well depth and the characteristics of the formations

being drilled.

The number of wells drilled usually responds to changes in

the price of crude oil. When crude oil prices were increasing

during the late 1970’s, companies invested in more drilling

20 Petroleum: An Energy Profile, 1999

$0

$100

$200

$300

$400

$500

$600

1970 1975 1980 1985 1990 1995

Dollars per Foot

Offshore

Onshore

Figure 4.5 Average Cost of Oil Well Drilling,

1970-1997

Source: American Petroleum Institute, Basic Petroleum Data Book,

January 1999, volume XIX, No. 1, Tables 4 and 5.

3 American Petroleum Institute, Joint Association Survey on 1997 Drilling Costs, (Washington, DC, November 1998), p. 4.

4 American Petroleum Institute, Joint Association Survey on 1997 Drilling Costs, (Washington, DC, November 1998) p.1 and Table 2.9.
activity. For the most part, U.S. drilling activity has decreased since the 1981 price peak. In 1986, the number of oil

wells completed fell almost 50 percent from the previous

year. Rising crude oil prices following Iraq’s invasion of Kuwait in 1990 helped increase drilling activity for the first time

since 1984. However, the total number of oil well completions fell from 35,118 in 1985 to 6,300 in 1998.5

Exploratory wells are those wells drilled to search in areas

not already proven to have oil reserves, to find the limits of a

newly-discovered reservoir, or to find new reservoirs in

fields where reserves are known to exist. In 1997, about 5

percent of all oil wells drilled were exploratory wells and the

remainder were development wells.6 Development wells are

those drilled in areas which have already been proven to have

a productive reservoir. Of all the oil and gas wells drilled in

1997, about 22 percent of the exploratory wells and about 81

percent of the development wells were successful in finding

hydrocarbons.

A long-term decline in average well productivity is now underway in the United States (Figure 4.6). On average, oil

wells produced just under 11 barrels per day, as in 1997. The

United States has a very large number of stripper wells,

wells which produce less than 10 barrels per day as compared

with many other oil producing countries. Because stripper

wells are less profitable, they are more seriously affected by

low crude oil prices. Many stripper wells have ceased production and were shut-in during either the price drop in 1986

or in 1998. Some of these wells may be reopened for production if crude oil prices increase and remain high. State oil and

gas production regulations require that oil wells shut-in for

more than a set period of months must be plugged and abandoned; i.e., the metal production casing is removed and the

well filled with cement through all producing and water-bearing zones.

Development and Recovery

When a commercially producible deposit of oil is found by

drilling, development wells are planned, drilled, and completed so that the oil can be brought up to the surface efficiently. In most producing wells, casing is cemented into

place beyond the zone to be produced and the casing is then

perforated so that oil can flow into the well. Occasionally,

perforation is done by bullets discharged from a specially designed firearm, but more often holes are made in the casing

by shaped explosive charges which are lowered into the well.

Smaller steel pipe, known as production tubing, is run inside

the casing and a packer is put in place between the tubing and

casing to isolate the producing zone from the rest of the casing. Crude oil is brought up through the tubing. A second set

of tubing in the casing can be used to produce oil from a second reservoir within the field. A “Christmas tree” is installed at the top of the casing and tubing to control the flowing oil. The Christmas tree is a set of valves and fittings

designed especially for the production of a particular well.

Well Testing

In most cases, the drill string must be removed from the well

in order to conduct well tests, but new automatic systems

which can provide certain measurements while drilling continues have been developed. Wells, both exploratory and development, are usually tested during and after drilling to

determine if an oil producing formation has been reached.

Well logging instruments may be lowered into a well to measure many characteristics, such as temperature, electrical resistance, and radioactivity. The logging data collected from

these instruments are used to determine the characteristics of

the rocks and fluids found in a well. Today, many wells are

drilled with equipment which measures these rock characteristics while the well is being drilled. Core samples provide

another means of determining rock and fluid characteristics,

as well as allowing visual examination of the well contents.

A core sample is a cylindrical section of the rock formation

taken from the center or side wall of a well. The well may

also be produced to a flare stack to judge the possible rate of

production.

Petroleum in an underground reservoir is usually under great

pressure. Because an open well has lower pressure, oil will

flow toward it. The rate at which oil will flow through the reservoir and into a well, where it can be raised to the surface,

depends on the permeability of the rock formation and the

thickness, or viscosity, of the oil.

Petroleum: An Energy Profile, 1999 21

0

5

10

15

20

1970 1975 1980 1985 1990 1995

Barrels per Well per Day

Figure 4.6 Average Productivity of U.S. Oil Wells,

1965-1997

Source: 1970-1997, Energy Information Administration, Annual

Energy Review 1997, DOE/EIA-0384(97).

5 Energy Information Administration, Monthly Energy Review, March 1999, DOE./EIA-0035(99/03), Table 5.2.

6 American Petroleum Institute, Joint Association Survey on 1997 Drilling Costs, (Washington, DC, November 1998) Tables 2.6 and 2.7.
A well is considered to have natural lift if it has sufficient

pressure and the oil has low enough viscosity to flow up

through the tubing to the surface on its own. Gas or water,

which reside in the reservoir with the oil, can provide the

pressure needed to create natural lift. Gas may be dissolved

in the oil or form a “gas cap” (also known as associated gas)

on top of the oil, or both. As the pressure is reduced in a gas

cap reservoir, dissolved gas is released from the oil and the

gas cap expands, pushing the oil through the reservoir and

into the well. Any water that is present in a reservoir will lie

underneath the oil, because oil is lighter than water, and creates a water drive, pushing oil toward the lower pressure in

the well. If natural lift is not present, artificial lift methods

must be used to bring the oil up. Many U.S. oil wells, under

production for a long time, have lost much of their natural

pressure. By 1997, about 96 percent of the producing oil

wells in the United States used artificial lift methods.7

Artificial lift is usually provided by pumps or by gas lift. The

most common type of pump is a walking beam pump (sometimes known as a horsehead pump), which provides the familiar up and down stroking action often seen at well sites.

Sometimes electrically or hydraulically powered submersible pumps are placed at the bottom of the well. Gas lift is created by injecting gas down the well between the casing and

tubing. Valves are opened up in the tubing allowing the gas

to mix with the oil, making it less dense and increasing its

ability to flow.

The rate at which oil flows through the reservoir can be increased by stimulation techniques which enlarge the spaces

in the formation. Acidizing and hydraulic fracturing are the

most frequently used methods. In the former, an acid, usually

hydrochloric acid, is pumped down the well into the pores

where it eats away some of the rock and opens larger spaces.

In hydraulic fracturing, a fluid is pumped down, under pres22 Petroleum: An Energy Profile, 1999

Gas

Oil

Water Water

Figure 4.7 Secondary Recovery Using Water Injection to Supplement Drive

Source: Energy Information Administration, Office of Oil and Gas.

7 “Producing Oil Wells: Paying the Price,” World Oil, Vol. 212, No. 2 (Houston, Texas: Gulf Publishing Company, February 1991) p. 64.
sure, causing the rock to crack. The fluid contains a propping

agent, usually sand, which settles into the cracks and holds

them open, but still allows oil to flow through.

The recovery techniques described above are usually referred to as primary oil recovery methods.When oil no longer flows sufficiently using the primary methods, secondary

and tertiary, or enhanced, recovery methods may be tried to

bring the remaining oil up. The use of these methods depends

on estimates of the amount of oil remaining and on the cost of

the method.

Secondary and Enhanced

Recovery

The most common secondary method is waterflooding.

Water is injected through wells at the surface into the reservoir. The water injection wells are placed so that the water

will push the oil ahead of it, out of the pore spaces, toward the

producing well (Figure 4.7).

There are three principal methods of enhanced oil recovery:

chemical flooding, miscible flooding, and thermal recovery.

Chemical flooding is the same as waterflooding except that

chemicals are mixed with the water to aid oil flow. Miscible

flooding uses carbon dioxide or other gases as a flooding

agent. Thermal recovery is accomplished by in situ combustion or steam injection. In the former, a fire is started underground, burning a portion of the oil. In the latter, steam is

injected into the well, either in a continuous flow or in cycles

(huff and puff) (Figure 4.8). Both methods heat the fluid in

the reservoir, thinning the oil and increasing its rate of flow

toward the well. Thermal methods also increase pressure,

which aids in pushing oil through the reservoir. Steam injection is the most frequently used enhanced recovery technique.

Preparation

After oil is brought to the surface, small pipelines called flow

lines carry it to a part of the production site known as the tank

battery. In addition to storage tanks, the tank battery contains

equipment for preparing the oil before further distribution.

The fluid coming out of nearly all wells is actually a mixture

of oil, gas, salt water, and sediment. First, any gas present is

separated from the oil and water, then the gas may then be

sent to a processing plant or re-injected to help maintain reservoir pressure and thereby production. Separation of the remaining mixture may be accomplished in special tanks

where the settling process separates water and oil, or it may

be assisted by special equipment such as a heater treater. The

Petroleum: An Energy Profile, 1999 23

Oil

Steam

Hot

Water

Steam

Figure 4.8 Enhanced Recovery Using Continuous Steam Injection

Note: In the cyclic, or huff and puff, method, steam is injected and oil is recovered through the same well. The well is shut in (not producing oil) for a

few days between steam injection and recovery.

Source: Energy Information Administration, Office of Oil and Gas.
remaining fluid may be put through several different treatments, depending on its contents. For example, sediment

may have to be removed, or a chemical treatment may be applied to remove unwanted gases like hydrogen sulfide and

carbon dioxide. Crude oil from offshore wells is usually processed through a separator on the platform then shipped via

pipeline to storage and treatment facilities onshore.

The physical properties of oil differ for each reservoir. The

price for which oil can be sold depends not only on volume

but also on the oil’s characteristics, particularly its specific

gravity and its sulfur content. Testing of the oil to determine

these properties is conducted at the well site by taking samples of oil from the storage tanks. Specific gravity is a measure of the density of the oil. Light, low density oil has a low

specific gravity. However, the specific gravity of oil is usually measured on the American Petroleum Institute (API)

scale which expresses gravity in terms of degrees API. Alow

specific gravity translates to high API gravity and vice versa.

Thus the lightest, least dense oils are those with the highest

API gravities.

Oil volume can be measured by several techniques but is usually accomplished by gauging the level of oil in a tank before

and after shipment or by allowing it to flow through a meter.

Temperature is also measured because it affects the volume

of the oil. Some sites today are equipped with Lease Automatic Custody Transfer facilities (LACT’s) which do most of

the measuring, sampling, and testing without human intervention. Oil that has been completely prepared is stored in

tanks at the well site until it is transported to the refinery.

Crude oil prices will continue to influence exploration and

production activity in the future. In the long run, U.S. domestic production will undoubtedly decline. The rate of decline

will be influenced not only by oil prices, but also by the dynamics of the resource base over time, as well as offsetting

technological advancements in exploration, development,

and recovery methods.

24 Petroleum: An Energy Profile, 1999

For more information on petroleum resources and reserves, look for the current issue of U.S. Crude Oil, Natural

Gas, and Natural Gas Liquids Reserves annual report, and for the most recent data on U.S. crude oil production,

see the Petroleum Supply Annual, Volume 1, both on the “Petroleum” page of EIA’s website at

http://www.eia.doe.gov/. World crude oil production and reserves can be found in the International Energy Annual on the “International” page of our website.
5. Petroleum Refining

The petroleum refining industry provides the link between

crude oil and the finished product. Because the uses for crude

oil as it comes from the ground are limited, the petroleum refinery is the key to unlocking the full potential of this valuable resource. There are many refinery processes employed

to transform crude oil into the array of products used in transportation, electric power generation, home heating, and

countless other applications.

The United States leads the world in refinery output, producing 23 percent of the worldwide output of petroleum products. 1 As of January 1, 1997, an estimated 20 percent of the

crude oil refining capacity in the world was located in the

United States.

Petroleum refining is one of the leading manufacturing industries in the United States. The value of shipments by the

petroleum refining industry accounts for about 4 percent of

the value of shipments by the entire manufacturing sector of

the U.S. economy.2 In 1996, the value of shipments by the

petroleum refining industry was an estimated $158 billion.3

Nearly one-half of all U.S. refinery output is motor gasoline.

The industry responds to changes in demand by adjusting refinery processes to vary the yield of gasoline and other products. For example, in 1921, the yield of gasoline per barrel of

crude oil was about 27 percent. In 1997, the gasoline yield at

U.S. refineries was about 46 percent, reflecting the high demand for automotive fuels.

The first phase in refinery processing, atmospheric distillation, uses heat to separate the various hydrocarbon components (Figure 5.1). Beyond the atmospheric distillation unit,

or “downstream” from this initial refinery process, are more

complex units that increase the refinery’s flexibility to process a wide range of crude oils and increase the yield of

lighter (low-boiling point) petroleum products such as gasoline. The streams of material coming from the distillation

unit can be used as finished products or they can become

feedstocks for the downstream processes described later in

this chapter and in the Appendix B.4 Downstream operations

include vacuum distillation units; “cracking” units that use

heat, pressure, or catalysts to increase the yields of lighter

products; “reforming” units that upgrade low octane naphPetroleum: An Energy Profile, 1999 25

Refineries employ many different processes to convert crude oil into numerous petroleum products.

1 Energy Information Administration, International Energy Annual 1997, DOE/EIA-0219(97) Table 3.2.

2 U.S. Department of Commerce, Bureau of the Census, 1996 Annual Survey of Manufactures, Statistics for Industry Groups and Industries (M96AS1),

Table 2.

3 U.S. Department of Commerce, Bureau of the Census, 1996 Annual Survey of Manufactures, Statistics for Industry Groups and Industries (M96AS1),

Table 2.

4 In addition to crude oil and the products of other refinery processes, “refinery inputs” (feedstocks for refinery processing units) can include natural

gas liquids (NGL’s) recovered in natural gas processing plants.
26 Petroleum: An Energy Profile, 1999

Figure 5.1 Crude Oil Distillation

Source: Energy Information Administration, Office of Oil and Gas.

Butane and Lighter

Gas Processing

Isomerization

Alkylation

Straight Run Gasoline

Motor Gasoline Blending

Vapors continue to

rise through trays to

top of column, where

the lightest products,

those with the lowest

boiling points, are

drawn off.

Kerosene

Hydrotreating

Middle Distillate Fuel Blending

Naphtha

Catalytic Reforming

Light Gas Oil

Distillate Fuel Blending

Catalytic Cracking

Thermal Cracking

Heavy Gas Oil

Catalytic Cracking

Thermal Cracking

Straight Run Residue

Vacuum Distillation

Thermal Cracking

Bubble caps force

vapors to bubble through

liquid standing on trays.

Vapor cools as it

bubbles through

liquid, condensation

occurs, and liquid

is drawn off.

Bubble Caps

Liquid Downflow

Vapors

Perforated trays allow

vapors to rise

through column

FURNACE

CRUDE

OIL

FUEL

LINE

Crude oil is heated in

furnace and vapor forms.

Heated liquid

and vapor enter

distillation column.
thas to a high octane gasoline blending component called

“reformate”; and process units that combine molecules to

yield products with specific properties. Some refineries also

have operations to pretreat feedstocks, remove impurities,

and enhance various product characteristics.

Crude oil is not a homogeneous substance. Crude oil varies

in color, viscosity, sulfur content, mineral content, and other

characteristics, depending on the source. The quality of

crude oil depends largely on its geographic origin, although

the time a reservoir has been in production is also a factor.

(The same reservoir will produce progressively heavier

crude oil over time, as the lighter oil is drawn off and heavier

oil remains.)

Not all refineries are alike. The complexity of a refinery depends upon the physical properties of the crude oil to be processed there and the characteristics of the desired product that

will be produced there. Because refinery process requirements differ with the quality of crude oil inputs, a refinery’s

geographic proximity to the source of its crude oil inputs can

influence its configuration.5

Modern refineries process various blends of many different

crude oils, and different configurations of refining units are

used to produce a given slate of products from available

crude oils. A change in the availability of a certain type of

crude oil can affect a refinery’s ability to produce a particular

product. For example, because the sulfur content of crude oil

affects the quality of finished products such as lubricants or

gasoline (e.g., corrosiveness, odor, and explosion characteristics), a refinery designed to process “sweet” (low-sulfur)

oil would need treatment facilities to remove the sulfur if

only “sour” (high-sulfur) crude oils were available. Gravity

(measure of the density of the crude oil) can also affect the

complexity of a refinery. The “light” crude oils, those that

have the highest API gravity (see Glossary), contain the largest proportions of easily extracted gasoline hydrocarbons,

while “heavy” oils (those with lower API gravity) require

more severe processing. The product slate at a given refinery

is determined by a combination of demand, inputs and process units available, and the fact that some products are the

result (co-products) of producing other products.

Refinery Process

Development

The product slate has always reflected changes in product demand. During the mid-1800’s, coal distillation produced an

oil used primarily for illumination. Both this early “coal oil”

and a “kerosene” produced by a similar process were smelly,

smoky products. However, demand for lamp oil was growing rapidly, and the discovery of a process for making a clean

burning kerosene met a ready market. Petroleum refining focused on crude oil distillation for kerosene production until

the advent of the automobile and the internal combustion engine. In the early 1920’s, gasoline became the preferred

product as the growing number of automobiles rapidly increased the demand for motor fuel. The growing demand for

gasoline spurred the development of new refinery processes

to increase gasoline yields and improve the quality of the finished product.

Thermal cracking, a severe form of heat processing, was

the first downstream process that changed the petroleum refining industry. Thermal cracking was followed by other developments in the late 1920’s and early 1930’s.

Polymerization produces high octane gasoline from byproducts of thermal cracking (olefins). Vacuum distillation

further processes the “residuum,” or product remaining in

the bottom of the crude oil distillation column that will not

distill at atmospheric pressure. The product left from the

vacuum distillation process can be made to flow more easily

by subjecting it to a thermal cracking process known as visbreaking. This process reduces the product’s viscosity (the

thick, gluey quality that impedes product flow). Coking, another severe thermal process, produces fuel gas, gasoline

blending stocks, distillates, and petroleum coke from products left from atmospheric or vacuum distillation.

During World War II, the petroleum industry focused its

technological expertise on products essential to the war effort, especially high quality aviation fuel. One result was the

development of alkylation, a process in which a catalyst is

used to produce a high quality gasoline component. This

process became widely used after the war to produce gasoline blending stocks. Other technological advances during

the war included catalytic cracking and isomerization.

Catalytic cracking is similar to thermal cracking, but utilizes

a catalyst to accelerate the rate of the reaction. Isomerization

is a process to produce high quality gasoline blending stocks

called isomers by changing the arrangement of atoms in the

hydrocarbon molecule without changing the chemical composition of the compound. The isomerization process uses

heat and a catalyst to convert straight-chained hydrocarbon

molecules to branched-chained hydrocarbon molecules with

the same chemical composition. This process increases the

octane number of the light gasoline components, normal

pentane and normal hexane, that are found in light, straightrun gasoline.

Catalytic reforming, a revolutionary process for converting

low grade naphthas to high octane gasoline, was a major development in the late 1940’s. Hydrotreating, a process to

remove contaminants that would damage the catalyst used in

catalytic reforming, was developed in the mid-1950’s. Hydrocracking, a process using hydrogen and catalysts to convert middle boiling range or residual products into lighter

products was developed in the 1960’s.

Beginning in the late 1970’s, the configuration of a refinery

reflected the influence of both international events and doPetroleum: An Energy Profile, 1999 27

5 Refinery configuration is a term that refers to the various types of processing units located at a refinery.
mestic policies. High quality gasoline blendstocks were

needed to meet the increasing demand for unleaded motor

gasoline, prompted by environmental concerns. Light, sweet

oils produced by certain members of the Organization of Petroleum Exporting Countries (OPEC) were especially in demand, because they require less severe processing than

heavy, sour oil to produce high quality motor gasoline blendstocks.

Federal Government price controls set in place in the early

1970’s gave a clear economic advantage to refineries that had

access to low cost domestic oil. The federally administered

“Crude Oil Entitlements Program” was implemented in 1975

to distribute oil supplies among refiners. This program included features which, in effect, provided a subsidy for small

refining companies, many of which had simple “topping” facilities and little or no downstream processing capability. (A

simple “topping” refinery will have a distillation tower, and

possibly a reformer and some sulfur treating capability,

while complex refineries will have more extensive downstream facilities.) A refiner who had access to light crude oils

needed only a distillation tower to produce motor gasoline.

Therefore, many simple refineries sprang up across the country, most notably in the Gulf Coast area. However, the end of

the Crude Oil Entitlements Program and decontrol of crude

oil prices in 1981 eliminated special cost treatment for small

refiners, and many of these less complex refineries, as well as

older, inefficient plants, shut down their operations.

The number of petroleum refineries in operation dropped

sharply in 1981, as 23 facilities closed and 47 others temporarily halted production, mainly as a result of the end of the

small refiners’ subsidies (Table 5.1). The largest loss in

crude oil distillation capacity6 occurred in 1982, when 43 refineries closed. Much of the loss in distillation capacity was

permanent; however, additions to downstream capability

offset the closings. Since 1980, the refining industry’s emphasis has shifted from increasing crude oil distillation capacity to investment in downstream charge capacity7

,

thereby increasing overall refinery complexity (Table 5.2).

This transition began several years before the passage of the

Clean Air Act Amendments in 1990 as a result of increased

demand for lighter, cleaner products that have to be produced

from increasingly heavier and more sour crude oils.

Downstream charge capacities do not necessarily measure a

refinery’s ability to produce a given product, because product mix is determined by many factors. Refiners are able to

estimate production capacity (Table 5.3) figures for certain

products under maximum operating conditions; that is, if all

the process units that produce a given product were running

at full capacity and were focused solely on production of that

product. Isomer production capacity more than quadrupled

between 1981 (131 thousand barrels per stream day) and

28 Petroleum: An Energy Profile, 1999

Year Vacuum

Distillation

Coking Other

Thermal

Cracking

Catcracking

Fresh*

Catcracking

Recycle

HydroCrackingHydroTreatingCatalytic

Reforming

Fuels Solvent

Deasphalting

1970 NA 837 641 4,212 NA 515 NA 2,501 NA

1975 NA 1,021 413 4,599 NA 801 NA 3,469 NA

1980 6,381 1,068 496 5,310 443 864 4,616 3,970 NA

1985 6,998 1,407 451 5,232 507 1,053 8,897 3,750 NA

1990 7,245 1,549 559 5,441 314 1,282 9,537 3,896 279

1995 7,248 1,785 338 5,583 169 1,386 10,916 3,867 251

1996 7,314 1,842 311 5,599 169 1,385 11,050 3,852 281

1997 7,349 1,910 139 5,595 155 1,388 11,041 3,727 275

Table 5.2 U.S. Operable Refining Downstream Capacity as of January 1

(Thousand barrels per stream day)

*Prior to 1980, includes both fresh and recycle catcracking.

NA= Not Available

Italics = Estimates are reported projected capacities.

Source: Energy Information Administration, Petroleum Supply Annual, Volume 1, Table 41.

Year Number of Refineries Crude Oil Distillation

1970 276 12,021

1975 290 14,961

1980 319 17,988

1985 223 15,659

1990 205 15,572

1995 175 15,434

1996 170 15,333

1997 164 15,452

Table 5.1 U.S. Operable Refining Capacity

as of January 1 (Thousand barrels per

calendar day)

Sources: 1970-1995 and 1997, Energy Information Administration,

Petroleum Supply Annual, Volume 1, Table 36; 1996: Petroleum

Supply Annual, 1996, Volume 2, p. 183.

6 Crude oil distillation capacity is generally measured in terms of “calendar days,” or the maximum amount of input that can be processed during a

24-hour period with certain limitations. Some downstream capacities are measured in terms of “stream days,” or the amount a unit can process running at

full capacity under optimal crude and product slate conditions for 24 uninterrupted hours.

7 Downstream charge capacity measures the amount of inputs, or “charge,” that can be processed in a particular type of downstream unit.
1997 in response to increasing demand for high octane unleaded gasoline blendstocks.

Quality of Crude Oil Input to

U.S. Refineries

The added downstream capacity and treatment processes increased the refiners’ flexibility, enabling them to produce a

mix of finished products from a wide range of domestic and

foreign crude oils. This reduced dependence on the more expensive high gravity, low-sulfur oils imported from the Middle East.

In 1977, Persian Gulf Nations8 (sources for many high quality crude oils) supplied 37 percent of total U.S. crude oil imports. However, since 1990, the supply sources for U.S.

crude imports have shifted toward Latin America. Imports

from Latin American countries nearly doubled from 1990 to

1997. During 1997, crude oil imports from Latin American

countries supplied 41 percent of total U.S. crude imports,

while the Persian Gulf supplied 20 percent. This change in

supply sources can, in large measure, be attributed to the fact

that Venezuela and Mexico have become heavily involved in

the U.S. refining business. In recent years, the Venezuelan

state oil company (PDVSA) and the Mexican state oil company (PEMEX) acquired 1.2 million barrels per day of U.S.

crude oil distillation capacity. After making these acquisitions, both companies invested in process upgrading to handle the heavy-sour Venezuelan and Mexican crude oils.

As crude oil imports from the Persian Gulf declined, the average gravity of imported crude oil dropped from about 34

degrees API in the late 1970’s to 30 degrees API in 1997.

This is because crude oils from Latin America, particularly

Mexican, Venezuelan and Guatemalan oils, are much heavier than Persian Gulf crudes. In 1997, the average weighted

API gravity of Persian Gulf crude imports was about 32 degrees, compared to 26 degrees for the average of imports

from Latin America. (The higher the gravity measured on

the API scale, the lighter the crude oil.) The sulfur content of

imported crude oil has risen from less than one percent in the

late 1970’s to about 1.6 percent in 1997. 9 As the sources of

crude oil continue to shift, changes in the characteristics of

crude oil inputs will continue to shape the configuration of

U.S. refineries.

Refinery Capacity and

Utilization

Because crude oil distillation is the first phase of refinery operations and provides the feedstocks (inputs) for many other

processes, crude oil distillation capacity,10 or the amount of

crude oil that can be processed in a refinery’s atmospheric

distillation units, is one measure of the refining industry’s

ability to satisfy demand. While refinery distillation capacity has generally paralleled product demand, the two do not

always move in tandem. Changes in demand stimulate

changes in refinery capacity as the industry adds, closes, or

modifies refineries to adjust to market requirements. The lag

between changes in demand and changes in capacity reflects

the lead time required to change the configuration of existing

facilities.

As of January 1, 1997, the 164 petroleum refineries in operation in the United States, ranged in size from small refineries

able to process 1,000 barrels of crude oil per day in their

crude oil distillation units to those able to process more than

400,000 barrels per day. Their combined crude oil distillaPetroleum: An Energy Profile, 1999 29

Year Alkylates Aromatics Asphalt

& Road Oil

Isomers Lubricants Marketable

Petroleum Coke

Hydrogen

(Million Cubic

Ft./Day)

Sulfur

(Short Tons/Day)

1970 893 NA NA NA NA NA NA NA

1975 1,106 NA NA NA NA NA NA NA

1980 951 434* 766 NA 236 246 1,569 NA

1985 917 215 767 219 243 424 2,572 NA

1990 1,030 290 844 456 232 341 2,607 24,202

1995 1,105 285 846 502 217 427 3,139 24,885

1996 1,122 286 850 505 217 428 3,204 26,014

1997 1,120 288 872 577 244 458 3,052 26,466

Table 5.3 U.S. Operable Production Capacity as of January 1

(Thousand barrels per stream day, except where noted)

*Includes isomerization.

NA = Not Available

Italics = Estimates are reported projected capacities.

Source: Energy Information Administration, Petroleum Supply Annual, Volume 1, Table 42.

8 Includes Bahrain, Iran, Iraq, Kuwait, Qatar, Saudi Arabia, and the United Arab Emirates.

9 Energy Information Administration, Form EIA-814 “Monthly Imports Report.”

10 “Crude oil distillation capacity” refers to capacity that is “operable”, i.e., actually in operation; not in operation or under active repair, but able to be

brought on line within 30 days; or undergoing repairs that can be completed within 90 days. Operable capacity is subdivided into “operating” or “idle”

capacity according to current status.
tion capacity totaled 15,452 thousand barrels per calendar

day.

Nearly one-half of the Nation’s crude oil distillation capacity

resides in the Gulf Coast region, which holds over one-third

of the petroleum refineries in the United States. Most of the

region’s refineries are located in Texas and Louisiana. Texas

has 30 refineries, with a combined crude oil distillation capacity of 4.0 million barrels per day, and Louisiana has 19 refineries with 2.4 million barrels per day of atmospheric

distillation capacity. California’s 24 refineries add about 1.9

million barrels of crude oil distillation capacity. The “top

ten” refining States, those with the highest individual crude

oil distillation capacity, account for 81 percent of the U.S. total (Table 5.4).

The U.S. refining industry’s ability to meet short-term increases in demand can also be measured by the rate at which

operable distillation capacity is utilized. The refinery utilization rate is expressed as a percent and represents gross inputs to crude oil distillation units divided by operable

capacity. The utilization rate fluctuates as refinery operations adjust to changes in demand. It reflects changes in refinery operations more rapidly than capacity changes do. For

example, capacity expansions begun in response to high demand levels through the early and mid-1970’s continued to

come on line even after demand peaked in 1978. At the same

time, gross inputs to distillation units leveled off and turned

downward in response to declining demand. As a result, refinery utilization declined steadily from 1978 to 1981, evidencing a slowdown in refining activity that was not

reflected in capacity figures until 1982.

However, during the 1980’s, the U.S. refining industry experienced a net loss of 120 refineries and approximately 3 million b/d of operable capacity. Conversely, there was a steady

rise in U.S. demand for petroleum products after 1983. Consequently, the amount of gross inputs to refineries rose steadily every year since then. As a result of the continual loss of

capacity every year, and in response to rising demand for refined petroleum products, the average annual refinery utilization rate increased from 69 percent in 1981 to 95 percent in

1997.

Refinery yield represents the ratio of a particular finished

product to inputs of crude oil and net inputs of unfinished oils

(Figure 5.2). Improvements in process technology and expansion of downstream process capability can lead to increases in the yields of light products. On the other hand,

increased use of heavier crude oils and changes in the mix of

products can result in a decrease in light-product yields.

Also, more stringent product specifications can require additional processing, which results in additional yield loss.

However, process technology improvements have enabled

refiners to avoid light-product yield declines and achieve

slight yield improvement. Refinery yields for finished motor

gasoline and distillate fuel oil, the two major refined products, have remained fairly steady throughout the 1990’s. Finished motor gasoline yield in 1997 was 46 percent and

distillate fuel oil yield was 23 percent. Residual fuel oil

yields dropped from 7 percent in 1990 to 5 percent in 1997.

Yields for petroleum coke and liquefied petroleum gases

each grew a percentage point between 1990 and 1997 to 5

percent.

30 Petroleum: An Energy Profile, 1999

Motor Gasoline (45.7%)

Distillate Fuel Oil (22.5%)

1

Jet Fuel (10.3%)

Residual Fuel Oil (4.7%)

Still Gas (4.4%)

Petroleum Coke (4.6%)

Liquefied Petroleum Gases (4.6%)

Asphalt & Road Oil (3.2%)

Petrochemical Feedstocks (2.9%)

Lubricants (1.2%)

Other (1.4%)

Figure 5.2 Product Yield from a Barrel of Crude

Oil, 1997

1 Includes kerosene, special naphthas, aviation gasoline, waxes, and

miscellaneous products.

Note: Components do not add to 100 percent due to independent

rounding and because of processing gain (an increase in volume that

occurs during refining).

Source: Energy Information Administration, Petroleum Supply

Annual 1997, DOE/EIA-0340(97)/1, Table 19.

State Number of

Operable

Refineries

Operable Crude Oil

Distillation Capacity

(Thousand

Barrels/Day)

Texas 30 4,043

Louisiana 19 2,430

California 24 1,911

Illinois 6 948

New Jersey 6 645

Washington 7 583

Pennsylvania 6 576

Ohio 4 509

Indiana 2 432

Oklahoma 5 408

Subtotal 109 12,485

U.S. Total 164 15,452

Table 5.4 Top Ten Petroleum Refining States as

of January 1, 1997

Note: Total capacity may not equal sum of components due to

independent rounding,.

Source: Energy Information Administration, Petroleum Supply

Annual 1996, DOE/EIA-0340(96), Table 36.
Petroleum: An Energy Profile, 1999 31

LPG Sources and Processing

Many terms are used to denote the various hydrocarbon compounds that are found in both the gaseous and liquid states. In

some cases these terms are used interchangeably, but for the most part the different terms refer to different compounds at

different stages of processing.

Liquefied petroleum gases (LPG’s) include ethane, ethylene, propane, propylene, normal butane, butylene, and

isobutane produced at refineries and natural gas processing plants. Other plants that separate raw natural gas plant liquids

into their various constituents, or “fractions,” in a distillation process known as “fractionation,” are called “fractionation

plants” or “fractionators.” Propane, butane, and mixtures consisting mainly of these two compounds are the most common

LPG’s.

Natural gas is a mixture of hydrocarbon compounds existing in the gaseous state or in solution with oil in natural

underground reservoirs. Hydrocarbon liquids condensed from “wet” natural gas coming from the well are known as

natural gas liquids (NGL’s). NGL’s are recovered at gas processing plants. They include the lighter liquids (ethane,

propane, and butane, and mixtures of these compounds) as well as the heavier pentanes plus (isopentane, nautral gasoline,

and plant condensate). Most natural gas processing plants yield “unfractionated streams,” or NGL mixes that are later

separated into their component parts at fractionators, to yield ethane, propane, butane, isobutane, and pentanes plus. Once

the liquids have been removed and the natural gas is ready for consumption, it is known as “dry” natural gas.

Liquefied refinery gases (LRG’s) are LPG’s produced at refineries. Refineries use large quantities of NGL’s from

fractionators as feedstocks and blendstocks. Smaller amounts of LRG’s flow from refineries to fractionators for

processing.

Dry Gas

Wet Gas

Gas Processing

Plant

Oil Wells Gas Wells

Crude Oil (Including Lease Condensate)

NGL

NGL

Unfractionated 

Stream Fractionator

LRG

Refinery

Ethane

Propane

Butane

Natural

Gasoline

Other 

Products

Ethane

Propane

Butane

Still Gas

Other 

Products

LPG

LPG

(LRG)
Refinery configuration is constantly changing to meet current requirements. Changing quality of crude oil inputs and

changing product requirements will continue to stimulate

technological advances and modifications in refinery configuration. Environmental requirements for cleaner burning

fuels and cleaner refinery processes have been foremost

among the factors that have influenced refinery configuration during the last decade. Innovations in catalyst design

and refinery process units will continue to allow greater

flexibility in processing heavy residual oils. Newly developed catalysts will also help refiners meet environmental

standards for sulfur in final products and in refinery emissions. Requirements for specialized hydrocrackers, hydrotreaters, and other downstream units are likely to increase

as refinery configurations adapt to increasingly stringent

product specifications.

32 Petroleum: An Energy Profile, 1999
Petroleum: An Energy Profile, 1999 33

Motor Gasoline Octane Enhancement

Motor gasoline is a complex mixture of relatively volatile hydrocarbons that have been blended to form a fuel suitable for

use in spark-ignition internal combusion engines. Various gasoline blends differ in properties that affect engine

performance, such as octane and volatility. The octane rating measures the anti-knock properties of a motor gasoline. (A

research octane number (RON) based on performance under research test conditions and a motor octane number (MON)

based on more severe operating conditions are averaged to produce the road octane number ((R+M)/2) that is posted on the

gasoline pump.) As automobile engines underwent design changes to increase power and efficiency, they required higher

octane gasolines to prevent uneven combustion known as “engine knock.” Volatility, (evaporative tendency) measured by

the Reid Vapor Pressure (RVP), affects engine starting and performance. (RVP represents the vapor pressure of the liquid

at 100 degrees Fahrenheit expressed in pounds per square inch.) Gasoline blends are adjusted to raise the RVP in winter,

which allows the gasoline to vaporize readily in the combustion chamber to provide for easy starting. The RVP is lowered

in summer so the gasoline will not vaporize in the fuel system causing a condition known as “vapor lock”.

Early gasolines produced simply by atmospheric distillation of crude oil did not satisfy the higher octane requirements of

the newer engines, so other methods were employed to boost octane; namely, greater use of complex “downstream”

refining processes, and the use of additivies such as lead. Because of lead’s toxicity, its use in automotive fuels was first

restricted with the passage of the Clean Air Act of 1970 requiring the design and manufacture of automobiles that could run

on low-lead and unleaded fuel and establishing a schedule for reducing the use of lead in gasoline. As environmental

concerns grew, the Environmental Protection Agency (EPA) continued to tighten lead level restrictions. By January 1,

1986, the lead content was limited to 0.1 gram per gallon, although the phase-in of EPA’s regulations permitted refiners to

use “lead credits” earned for gasoline containing less than the maximum amount of lead allowed to offset production of

gasoline that exceeded the lead limit until December 31, 1987. The Clean Air Act Amendments of 1990 completely banned

the use of lead in motor gasoline after December 31, 1995.

The gradual elimination of lead increased the use of other additives, including compounds produced in refineries, such as

butane and the aromatics benzene, toluene, and xylene, to enhance gasoline octane ratings. Other additives used to boost

octane ratings, termed “oxygenates” because they raise the oxygen level of gasoline, include alcohols such as ethanol and

ethers such as methyl tertiary butyl ether (MTBE).

Some of these blendstocks have various undesirable environmental properties. For example, the addition of butane to

gasoline increases its volatility, increasing the loss of unburned hydrocarbons from the fuel tank or carburetor. Because of

the environmental hazards associated with the escape of hydrocarbons through evaporation, EPA promulgated new

regulations in 1989 to restrict gasoline volatility in the summer months. Later EPA regulations and the Clean Air Act

Amendments of 1990 further restricted volatility beginning in 1992. The Clean Air Act Amendments also required the use

of “reformulated” gasoline to reduce the formation of ground level ozone in certain metropolitan areas beginning in 1995.

Beginning in November 1992, gasoline sold in areas that exceed air quality standards for carbon monoxide are required to

contain specific levels of oxygen to reduce carbon monoxide emissions in the wintertime. As environmental concerns

grow, oxygenates (alcohols and ethers) are becoming a larger component of gasoline supply. Presently, ethanol and MTBE

are the most widely used oxygenates.

For the most recent data on refinery inputs, production, and capacity utilization, look for the current issues of the

Weekly Petroleum Status Report and the Petroleum Supply Monthly on the “Petroleum” page of EIA’s website at :

http://www.eia.doe.gov/ . Refinery crude oil distillation and downstream capacity data are published by State and

company in the Petroleum Supply Annual, Volume 1, also on the “Petroleum” page. These data are available every other year (i.e., 1996, 1998, etc). In addition, historical series for the total U.S. are available in the Annual Energy Review on the “Historical” page of our website. World refinery production and world refinery capacity can

be found in the International Energy Annual on the “International” page.
6. Transportation and Storage

Storage facilities and four major transportation modes—water, highway, rail, and pipeline—form a system which moves

crude oil from wells to refineries, and distributes refined

products to final consumers. In the United States, the sources

of oil have, over time, moved farther and farther from the major consuming areas. Distance, geography, technology, and

economics all influence the types and amounts of transportation and storage used.

The first crude oil produced in the United States was collected in wooden barrels and transported to the refinery by

boat, train, or horse drawn wagon. Barrels (equivalent to 42

U.S. gallons) are still the standard measure for petroleum. At

first, large quantities of oil were stored in oblong wooden

boxes or in pits dug in the earth.1 In the 1860’s, storage methods improved rapidly; first, when circular wooden tanks

were developed and again, shortly thereafter, when riveted

wrought iron tanks were first built. These remained the primary means of storing crude oil until after the turn of the century when steel storage tanks were introduced.

The first successful pipelines were constructed in the middle

1860’s. They were short and used mainly to connect producing wells with water or rail transportation facilities. Longer

pipelines were soon being built and began to compete with

long-distance rail transportation. Controversy marked the

late 1800’s as the different transportation modes fought for

market share. Eventually, pipelines won some protection

through the courts. Rail continued to be an important means

of transporting petroleum, especially refined products, until

about 1930 when the technology for shipping more than one

product through a single pipeline was developed.

Before World War II, oil-carrying ships, known as tankers,

were a chief means of transporting petroleum products from

the refineries on the Gulf Coast to the Nation’s largest consuming areas on the East Coast. But during the war, the sinking of more than 150 tankers in submarine attacks and the

perceived threat to remaining tankers led to a surge in building and use of pipelines.

A resurgence of domestic water transportation of petroleum

followed the beginning of significant Alaskan production in

the late 1970’s. By 1983, water transportation of petroleum

peaked and accounted for nearly 52 percent of all domestic

transportation of petroleum (Figure 6.1). However, by 1995,

water transportation of petroleum had declined to about 38

percent of all domestic petroleum transportation. In contrast,

Petroleum: An Energy Profile, 1999 35

Constructing Pipelines

After several attempts to build cast iron pipelines, the first successful pipelines were constructed of wrought iron in the

middle 1860’s. In 1895, steel pipe was introduced. Several people, armed with large wrenches called tongs, were needed

to screw together the lengths of steel pipe. Advancements in welding technology in the 1920’s led to improvements in the

construction of both storage tanks and pipelines. Today, pipe sections are welded together, either by hand or by automatic

welding machines. Pipelines are nearly always buried underground, so the first step in onshore construction is digging a

trench. Machines suspend pipe sections over the ditch while they are welded. Bending machines can bend the pipe to fit

the contour of the land if necessary. Before burying, the pipeline is coated with a corrosion inhibitor, then wrapped in

protective paper or plastic tape. Welds are inspected by x-ray to ensure there will be no leaks and the pipeline is tested,

usually by running water through it under pressure.

The most common method of offshore construction uses a lay barge. Offshore pipe sections usually are coated first, then

welded on the barge. As the barge slowly moves forward, the welded pipeline slides off the back into the water. An outer

coating of cement is generally applied before putting the pipeline in place to weight it down and keep it from floating off

the sea bottom. Another type of offshore construction uses a reel barge, which carries already welded pipe wound on a

large spool or reel. As the barge moves along, the pipe is unreeled and let out the back of the barge carefully so the metal

will not crack as it unreels. Reel barges only lay smaller diameter pipe (2 to 12 inches). Offshore lines are usually buried

after they have been laid on the ocean floor.

The construction of the Trans-Alaska Pipeline was a challenge, partly because it was such a large pipeline in diameter and

length, but also because of harsh weather conditions and Alaska’s sensitive environment. Building pipelines in arctic

regions is hampered by permafrost. Oil moving through a pipeline is warm and can melt the permafrost. Continual melting

and re-freezing puts stress on the pipeline, increasing the possibility of leaks, and also can affect the natural environment of

the area. In order to solve this problem, the Trans-Alaska Pipeline was built on aboveground supports in permafrost areas.

1 A. Marks, Petroleum Storage Principles (Tulsa, Oklahoma: PennWell Books, PennWell Publishing Company, 1983), p.4.
pipelines as a means of transporting petroleum grew steadily

over this period, and by 1995, accounted for nearly 58 percent of all petroleum transported. Altogether, crude oil and

refined products were carried by pipeline, water carriers,

trucks, and railroads over 1,045 billion ton-miles in 1995.2

Most crude oil arrives at the refinery via pipeline (Table 6.1).

Trucks are mainly used to deliver products from bulk storage

to retail outlets or final consumers, although they may occasionally transport crude oil from very remote field storage

sites. Railroads carry only a small amount of petroleum, generally products.

Storage facilities are located along transportation routes to

accommodate the different rates at which various transportation modes can handle oil and refined products. Gathering

smaller volumes into larger batches or dividing up large

batches allows the cargoes to meet the capacities of the next

transportation mode. Storage facilities are also found at refineries and at wholesale and retail marketing facilities

where products are stored in bulk prior to being sold to consumers in smaller amounts.

Transportation

The shipment of Alaskan crude oil comprises a significant

portion of the U.S. petroleum transportation system. Most

36 Petroleum: An Energy Profile, 1999

0%

25%

50%

75%

100%

1975 1980 1985 1990 1995

Pipeline Water Truck & Rail

Figure 6.1 Petroleum Transportation by Mode of Travel, Selected Years 1975-1995

Sources: 1975-1990: Association of Oil Pipelines, "Shifts in Petroleum Transportation." 1991-1995: Eno Transportation Foundation, Inc.,

Transportation in America.

Transport Method/Source Receipts

Pipeline

Domestic ............... 1,849,835

Foreign ................ 923,008

Tanker

Domestic ............... 482,840

Foreign ................ 1,813,976

Barge

Domestic ............... 83,764

Foreign ................ 11,644

Tank Car

Domestic ............... 6,040

Foreign ................ 0

Trucks

Domestic ............... 69,492

Foreign 0

Total

Domestic ............... 2,491,971

Foreign................ 2,748,628

Table 6.1 U.S. Refinery Receipts of Crude Oil by

Method of Transportation and Source,

1996 (Thousand Barrels)

Source: Energy Information Administration Petroleum Supply

Annual, 1996, Volume 1, Table 46.

2 American Petroleum Institute, Basic Petroleum Data Book, Volume XVIII, Number 2, July 1998, Table 2.
Alaskan oil is transported via the Trans-Alaska Pipeline

more than 800 miles, from the oil fields in northern Alaska to

the port of Valdez on Alaska’s southern coast. From Valdez,

the crude oil is carried by tankers to ports on the West Coast.

In addition to transporting crude oil from Alaska, tankers

bring in foreign imports and carry refined products between

the Gulf Coast and East Coast.

Most crude oil shipped within the continental United States

occurs via pipeline from the Gulf Coast to the Midwest region, while tanker and barge shipments of crude oil account

for only a small portion that occurs exclusively between the

Midwest and East Coast regions. Conversely, tanker and

barge shipments of petroleum products account for a much

larger share of the overall movement of petroleum products

within the continental United States, although pipelines continued to be the primary means of shipping petroleum products to end-use markets. Most petroleum products shipped

via pipelines occur between the Gulf Coast and Midwest and

East Coast regions (Figure 6.2).

Ocean-going ships were used to transport crude oil as early

as 1861, when barrels of oil were carried on a ship from the

United States to England. Within just a few years, tankers in

which the hull serves as an oil tank were built.3 In modern

tankers, subdivided hulls allow more than one product to be

carried on each trip and prevent the liquids from shifting

enough to destabilize the ship. Today’s tankers range in size

from about 70,000 barrels of capacity to over 3.5 million barrels.4 Supertankers about one and a half times the size of the

standard World War II tanker, were introduced in the 1950’s.

By the 1960’s they had been surpassed in size by “very large

crude carriers” (VLCC’s). In 1979, “ultra large crude carriers” (ULCC’s) began carrying oil.5

Attention focused on the environmental hazards of tanker

transport when the Exxon Valdez ran aground off the coast of

Petroleum: An Energy Profile, 1999 37

Crude Oil (Tanker and Barge Shipments) Petroleum Products (Tanker and Barge Shipments)

Crude Oil (Pipeline Shipments) Petroleum Products (Pipeline Shipments)

1,976

70

71

90

29

16

818

2,296

7

4

17

123

3

52

4

796

4

97

26

34

2

14

98

181

284

28 58

95

Figure 6.2 Inter-Regional Movement of Crude Oil and Petroleum Products by Water and Pipeline, 1997

(Thousand Barrels per Day)

Note: Arrows vary in size to show the relative difference in inter-regional shipments.

Source: Energy Information Administration, Petroleum Supply Annual, 1997, DOE/EIA-0340(97)/1.

3 Energy Information Administration, Petroleum Supply Monthly (December 1983), DOE/EIA-0109(83/12), “An Overview of Petroleum

Transportation,” p.x.

4 The capacity of oil tankers is expressed in deadweight tons. This measure refers to the lifting capacity of a ship in long tons (2,240 pounds or 1.016

metric tons). The volume of petroleum that can be carried depends on the characteristics of the product as well as tanker size, but one deadweight ton is

equivalent to about 7 to 8 barrels of crude oil.

5 Supertankers are tankers with capacity above 24,000 deadweight tons. VLCC’s range in size from 160,000 to 319,999 deadweight tons and ULCC’s

are those tankers with capacity of 320,000 or more deadweight tons. Source: M. Champness and G. Jenkins, Oil Tanker Databook 1985 (London:

Elsevier Applied Science Publishers, 1985), Glossary.
Alaska in 1989, spilling some 240,000 barrels of crude oil

into Prince William Sound. The Oil Pollution Act of 1990,

which was signed into law on August 18, 1990, was a direct

outgrowth of concern over that spill. The Act sets forth

cleanup and prevention measures for oil spills and requires

the gradual phase-out of single-hull tankers. Beginning in

January 1995, new tankers traveling in U.S. waters (except

for vessels that might respond to a spill) must have double

hulls.

California has the only port (Long Beach) in the contiguous

United States capable of handling the very large crude carriers, and there are no ports deep enough to accommodate the

ultra large carriers. Imports carried by very large and ultra

large tankers are often transferred into smaller ships before

continuing to the United States. These transfers occur at

deep water Caribbean ports and at seas, but the Louisiana

Offshore Oil Port (LOOP) has reduced the need for transfers

since it opened in 1981. The LOOPis a storage and transportation facility 18 miles offshore in the Gulf of Mexico where

the water is deep enough to accommodate ultra large tankers.

It consists of a platform, which serves as an operations base,

and buoys. Tankers dock at the buoys where they are free to

move with current and winds. Hoses connect the cargo hold

of the ship to the buoy. Oil is off loaded through the hoses

and buoy and runs into a 48-inch diameter pipeline which

carries it to salt cavern storage facilities in Louisiana.

In recent years, ocean-going barges have been used to move

petroleum short distances between points on the Atlantic and

Gulf Coasts, but barges are designed primarily for the

calmer, shallower waters of inland waterways. They are used

largely to transport petroleum along the Mississippi and

Ohio river systems. They are also used often on inland waterways in the Gulf States and in some Northeast canals and

rivers. Crude oil entering at Gulf Coast ports, if not refined

there, may be moved up the Mississippi and Ohio Rivers to

refineries in the Midwest. More often, however, barges transport refined products.

Barges are flat-bottomed boats that, like tankers, usually

have subdivided hulls which serve as oil tanks and can carry

more than one product at a time. Individual barges carry

much less than tankers, up to about 30,000 barrels,6 but they

are usually lashed together in groups. Most barges cannot

move on their own but are pulled or, more often, pushed by

towboats at speeds of about 6 miles per hour.7

Tank trucks operate throughout the United States, mostly on

short-haul routes. Tank trucks for transporting petroleum

products first appeared about 1915. They are the smallest of

the oil carriers, being able to transport only a few hundred

barrels. Some are compartmentalized to hold more than one

type of product. Because of their small size, they can reach

remote areas.

Railroads are used to fill gaps between other transportation

modes, mainly to transport heavy products like asphalt, residual fuel oil, and lubricants, which are difficult or impossible to move through pipelines. There are two basic types of

rail tank cars—pressurized and unpressurized. Pressurized

cars carry very volatile products such as liquefied petroleum

gases.

Pipelines serve many areas of the United States (Figure 6.3).

The major long-distance pipelines are the crude oil pipelines

across Alaska, crude oil pipelines running from the Gulf

Coast to the Midwest, and product pipelines running from

the Gulf Coast refineries to the East Coast, mainly New York

and New Jersey . A recent and important addition to the pipeline system is a crude oil line running from California to

Texas. New England has notably few pipelines. There are

many pipelines in the Gulf of Mexico and off the California

coast which connect offshore production sites with facilities

on land.

Except for large tankers, pipelines are the least expensive

means of transporting petroleum, and large pipelines usually

are more economical to operate than small ones. The smallest pipelines are the flow lines from the wells which usually

range from 2 to 6 inches in diameter.“Gathering” lines, up to

about 12 inches in diameter, transport crude oil from producing fields to long-distance “trunk” pipelines which are usually much larger. The Trans-Alaska and LOOP pipelines, at

48 inches in diameter, are the largest pipelines in the United

States.8

Crude oil and products move through a pipeline at up to 6

miles per hour. Pumps at the beginning and at intervals along

the line provide the force to move the oil. Pump stations

along the line are usually controlled by computer from one

central location. The computers are also used to keep track of

shipments and deliveries. Telegraph lines were used to relay

information along the earliest pipelines. Today satellite

communications are often used.

Before the introduction of “batching” in the 1930’s, pipelines

were used almost exclusively to transport crude oil. Batching enables pipelines to run several different products back to

back, maintaining a continuous flow of liquid in the pipe. To

minimize mixing at the interface of two products, the order in

which batches enter the line is controlled. The products remain separated because of their different densities. Differences in density also signal the pipeline operator of the

beginning and end of particular batches. Occasionally,

batches are separated by a rubber sphere or other physical

barrier.

In the United States, most oil pipelines are operated as “common carriers” which means that the pipeline owner does not

take title to the oil being shipped, but simply provides the

38 Petroleum: An Energy Profile, 1999

6 S.P. Porter, Petroleum Accounting Practices (New York: McGraw-Hill Book Company, 1965), p. 371.

7 Energy Information Administration, Petroleum Supply Monthly (December 1983), DOE/EIA-0109(83/12), “An Overview of Petroleum

Transportation,” p.x.

8 J. L. Kennedy, Oil and Gas Pipeline Fundamentals (Tulsa, Oklahoma: Pennwell Books, PennWell Publishing Company, 1984), p.51.
Petroleum: An Energy Profile, 1999 39

Crude Oil Pipelines

CANADA

GULF OF

MEXICO

ATLANTIC OCEAN

PACIFIC OCEAN

MEXICO

CANADA

GULF OF

MEXICO

ATLANTIC OCEAN

PACIFIC OCEAN

MEXICO

Petroleum Product Pipelines

Figure 6.3 Petroleum Pipelines in the United States as of December 31, 1997

Source: National Petroleum Council, Petroleum Storage & Transportation, 1998.
40 Petroleum: An Energy Profile, 1999

The Strategic Petroleum Reserve

In 1975, following the oil shortages and resulting economic problems created by the 1973-1974 oil embargo, Congress

enacted the Energy Policy and Conservation Act which called for the Government to develop a Strategic Petroleum

Reserve (SPR). The purpose of the SPR is to store crude oil which can be drawn upon to prevent shortages in domestic

markets during a major interruption of crude oil supplies. SPR use is designated for emergency situations, such as when a

disruption of imports, sabotage, or a natural disaster creates a severe national shortage that will threaten national safety and

the national economy. Only the President has the authority to order that the SPR be used. In the event of a SPR

distribution, the oil is sold to bidders in an open market.

In 1977, the Federal Government began purchasing crude oil and storing it in salt caverns. SPR facilities include six

storage sites in Louisiana and Texas and a marine terminal at St. James, Louisiana. Government-owned pipelines connect

the storage sites to commercial crude oil pipelines and marine terminals through which the oil would be distributed. Most

of the SPR crude oil has been purchased from foreign sources.

In September 1990, the Energy Policy and Conservation Act was amended to authorize a small sale of SPR oil to test the

Reserve’s distribution and sales system. On September 26, the President directed the Department of Energy to conduct a

sale of about 5 million barrels of SPR crude oil. After receipt and evaluation of all bids, 3.9 million barrels of crude oil

were delivered to 11 purchasers between October 19 and December 2. Shortly thereafter, the start of the Persian Gulf War

prompted the first emergency distribution of SPR oil. In January 1991, the International Energy Agency, of which the

United States is a member, agreed to a plan for releasing some oil from reserves if a war began. On January 17, President

Bush announced that 33.8 million barrels of SPR oil would be sold in conjunction with that plan. Because of changing

market conditions, including continued oil surpluses and falling prices, bids covering only 17.3 million barrels were

eventually accepted. Most of the oil was delivered in February and March. However, on February 11, 1999, the Secretary

of Energy announced an initiative to partially refill the SPR with federal royalty oil from production in the Central Gulf of

Mexico. The plan was specifically designed to replace approximately 28 million barrels of oil sold from the SPR in fiscal

years 1996 and 1997 largely for deficit reduction purposes.

The SPR is usually seen as a replacement for imports, and the amount stored is often described in terms of the number of

days of imports it could replace. The crude oil stored in SPR at the end of 1998, for example, represented about 60 days of

net petroleum imports. Currently, the SPR has 564 million barrels of crude oil in storage.

The Strategic Petroleum Reserve

0

100

200

300

400

500

600

700

1977 1979 1981 1983 1985 1987 1989 1991 1993 1995 1997

Million Barrels

Beginning of Year Stocks Additions from Imports Additions from Domestic Sources

Note: 1990, 1991, 1996, and 1997 additions are reduced by the amount withdrawn for sale .

Source: 1977-1996, Energy Informaiton Administration, Annual Energy Review 1996, DOE/EIA-0384(96); 1997: Energy Information

Administration, Petroelum Supply Annual 1997 , DOE/EIA-0340(97).
transportation service. As common carriers, pipelines must

be accessible to all oil that meet their specifications, regardless of ownership, and are subject to Government regulations

concerning rates and operating practices. Pipelines are also

subject to environmental regulations because their construction and the possibility of leaks during operation pose a danger to animal and plant life as well as ground water.

Storage

In the producing field, most crude oil is first stored in a battery of tanks, sometimes called lease tanks, where the oil

from many wells is collected. Imported oil is usually first

stored at a marine terminal at the port of entry where crude oil

and products are unloaded from tankers into storage to await

further shipment via inland transport networks. At refineries, incoming crude oil waits in storage tanks until it can be

processed; refined products are held separately in tanks until

enough is accumulated for blending or shipment. Pipeline

pumping stations may have storage facilities, referred to as

tank farms, where crude oil or products can be detained for

transfer to another line, to await repairs on the line, or to be

measured and recorded (Figure 6.4). Products are often sent

from the refinery to storage at bulk terminals or bulk storage

plants, from which products are resold and/or distributed locally (Figure 6.5). The final two storage phases for most petroleum products are storage tanks at retail sales outlets and

individual consumers’ storage tanks, including gasoline

tanks of cars and home heating oil tanks.

Crude oil and petroleum products are stored in bulk in

above-ground tanks, underground tanks and caverns, and

offshore storage facilities. Above-ground tanks are the most

common type of storage in the United States. Underground

tanks are used primarily for storing gasoline and diesel fuel at

service stations. Underground caverns are used around the

Petroleum: An Energy Profile, 1999 41

0

100

200

300

400

500

600

Strategic

Petroleum

Reserve

Tank

Farms and

Pipelines

Refinery Leases Alaska InTransit

Million Barrels

Figure 6.4 U.S. Crude Oil Stocks by Storage

Facility, December 31, 1997

Source: Energy Information Administration, Petroleum Supply

Annual 1997, DOE/EIA-0340(97).

0 10 20 30 40 50 60 70

Motor Gasoline

Distillate Fuel Oil

Residual Fuel Oil

Jet Fuel

Asphalt and Road Oil

Lubricants

Petroleum Coke

Million Barrels

Pipeline

Bulk Terminal

Refinery

Figure 6.5 Stocks of Major Petroleum Products by Storage Facility, December 31, 1997

Source: Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97).
world to store both crude oil and products, but in the United

States they are used primarily for crude oil and liquefied petroleum gases.

Except for their roofs, the above-ground tanks are of similar

construction. Steel plates are bolted or welded together to

form the cylindrical shell. Tank bottoms rest on a foundation

of earth or concrete, and individual or groups of tanks are surrounded by a dike to contain oil in case of a spill. Tanks are

generally painted on the outside with white or reflective

paint to reduce heat absorption. Limiting corrosion and rust

is a primary maintenance problem. Cathode systems, which

use weak electric currents to prevent corrosion, are sometimes built into tanks.

Petroleum and petroleum products are volatile substances

that evaporate easily. When stored, the liquid and the vapor

expand and contract with changes in temperature. Tank roofs

are designed to accommodate changes in the vapor pressure

inside the tank and to minimize the loss of vapor during filling and emptying. Several types of roofs have been developed for different products and storage situations. A “fixed”

or “cone” roof, attached to the tank shell around its edges, expands or contracts when vapor pressure changes. These

tanks are generally used to store crude oil and products with

low vapor pressure such as kerosene, fuel oil, and diesel oil.

Floating roofs, lying on top of the liquid inside the tank, help

to prevent loss by evaporation. They also increase safety and

reduce maintenance because potentially explosive and corrosive vapors cannot build up under the roof. Alifter roof fits

tightly over the outside of the tank and raises up and down as

vapor pressure changes. Products with high volatility, such

as gasoline, are usually stored in floating roof or lifter roof

tanks. Floating roof tanks are practical at sites where there is

frequent filling and emptying because they reduce vapor loss

during these operations.

Most underground storage tanks (UST’s) are constructed of

carbon steel. Fiberglass-reinforced plastic and corrosionprotected steel are also used. Environmental problems associated with leaking tank systems led to legislation in 1984

authorizing EPA regulation of UST’s. In 1988, EPA issued

technical standards and financial responsibility regulations

aimed at preventing leaks and addressing cleanup costs. EPA

regulations requiring that certain underground storage tanks

be protected from corrosion, overflow, and use leak detection systems were phased in over a 10 year period that ended

in December 1998.

Highly volatile petroleum products, such as propane and butane, are difficult to store under normal temperature and

pressure condtions. Special refrigerated and pressurized

tanks were developed in the 1920’s and 1930’s to store these

products. Very thick oils may be stored in heated tanks.

Storage facilities need enough tank capacity to hold the

maximum shipment they expect to receive; but because filling and emptying are continuous, tanks are, on average, used

at only about one-half of their capacity. At the beginning of

1997, there were 842 million barrels of shell storage capacity—the maximum amount a tank could hold if all its storage

space were usable—at refineries and gasoline blending

plants in the United States.9 The practical measure of how

much a tank can hold is its working storage capacity, or the

tank’s maximum capacity less empty space at the top required for safety and non-accessible space at the bottom. At

the beginning of 1997, the United States had about 745 million barrels of working storage capacity at refineries and

blending plants.10

Three types of underground caverns can be used to store oil:

solution-mined salt caverns, conventionally mined rock caverns, and reused mines. In the United States, only solutionmined salt caverns are used to any extent. Salt caverns in

Louisiana and Texas contain oil for the Strategic Petroleum

Reserve while salt caverns in Texas, Mississippi, and Kansas

are major storage sites for liquefied petroleum gases. Underground salt deposits are good storage containers for oil because the oil cannot permeate the salt structure. They are

relatively easy to construct by solution-mining (leaching),

wherein a well is drilled and fresh water is pumped into the

deposit to dissolve the salt. When the cavern is the preferred

size and shape, it is filled with oil pumped in through the

well. The oil displaces the brine pushing it up and out of the

cavern. In most salt caverns used for working storage, oil is

removed by pumping in saturated brine to displace the oil.

Offshore storage systems have been developed to collect oil

where pipelines are not readily available to ship it to onshore

storage sites. Some systems in use today are converted tankers (floating storage) and steel or concrete tanks on the sea

floor. The major technological problem in developing offshore storage is maintaining stability in ocean currents.

Stocks

The petroleum distribution system consists of three sectors

designated primary, secondary, and tertiary. The primary

sector includes the shipment and storage of crude oil, refining, and the delivery and storage of products at local bulk terminals (wholesale marketing facilities having at least 50,000

barrels of storage capacity or receiving products by barge,

tanker, or pipeline). The secondary sector includes bulk

plants (marketing facilities having less than a 50,000-barrel

capacity and receiving products by rail or truck only) and retail establishments. Final users comprise the tertiary sector.

Stocks of crude oil and petroleum products are volumes in

storage at a particular time. Crude oil stocks held by private

businesses in the primary sector fluctuated around 250 mil42 Petroleum: An Energy Profile, 1999

9 Energy Information Administration, Petroleum Supply Annual 1996, DOE/EIA-0340(96)/1, Table 44.

10 Energy Information Administration, Petroleum Supply Annual 1996, DOE/EIA-0340(96)/1, Table 43.
lion barrels from 1949 until 1976, when a buildup of inventories began (Figure 6.6). As of December 31, 1997, primary

stocks of crude oil were 305 million barrels. Fluctuations in

crude oil stocks can occur because of changes in the demand

for refined products, in the expected availability of crude oil

supplies, and in the cost of holding inventories. Refiners

may keep crude oil stocks to protect themselves from having

to shut down if an expected shipment fails to arrive. Stocks

of crude oil held by private industry usually are maintained at

or above the minimum operating inventory level, the minimum level needed to sustain operations of the distribution

system. Below that level, operating problems begin to occur.

Stocks played an important role during the Persian Gulf crisis in 1990 and 1991. Prior to Iraq’s invasion of Kuwait, petroleum stocks in the United States and in the rest of the

world were higher than usual. These relatively high inventory levels cushioned the impact when the United Nations

Security Council approved an embargo against oil exports

from Iraq and Kuwait that reduced world oil supplies by an

estimated 4.3 million barrels per day. During the crisis, U.S.

stocks were drawn down more rapidly than usual, leaving

crude oil stocks at the end of 1990 lower than they were at the

end of other recent years.

To guard against the impact of a major, long-term shortage of

crude oil and reduce concerns about supply interruptions, the

United States established the Strategic Petroleum Reserve

(SPR) (see page 40). In 1977, the SPR fill rate began with

imported crude oil. By 1994, the SPR had reached its maximum storage of 592 million barrels.11 As of the end of 1997,

the SPR contained 563 million barrels of crude oil.12

As demand grew following World War II, primary stocks of

petroleum products increased. In 1980, they began to decline

sharply, primarily reflecting a decrease in stocks of distillate

fuel oil and motor gasoline. High carrying costs and volatile prices contributed to the gradual decline in product

stock levels in the 1980’s. Stocks of products also fluctuated from month to month due to seasonal demand. For

example, refiners may increase their stocks of products

prior to a seasonal demand peak.

It is difficult to measure stocks in the secondary sector

because few data are collected from many retail outlets.

The National Petroleum Council (NPC), however, estimated in their 1998 study, that inventories of products

held at bulk plants were 22 million barrels and inventories at retail outlets were 44 million barrels.13

It is practically impossible to measure the amount of petroleum stocks held in the tertiary or end-use sector, although in the event of a supply disruption they could be

Petroleum: An Energy Profile, 1999 43

0

200

400

600

800

1000

1200

1949 1959 1969 1979 1989 1997

Million Barrels

Petroleum Products

Crude Oil, excluding SPR

Figure 6.6 U.S. Stocks of Crude Oil and Petroleum Products, End of Year 1949-1997

Source: 1949-1996: Energy Information Administration, Annual Energy Review 1996; 1997: Energy Information Administration, Petroleum Supply

Annual 1997.

11 Energy Information Administration, 25th Anniversary of the 1973 Oil Embargo, DOE/EIA-0624, (August 1998), p. 9.

12 Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1, p. 7.

13 National Petroleum Council, Petroleum Storage and Transportation, Volume IV (Washington DC, 1998), p. 1-8.
very important. Tertiary stocks do fluctuate, especially

if a shortage or substantial price change is anticipated.

For example, during the 1978 oil crisis, people waited in

long lines to top off their automobile tanks, thus keeping

their holdings of gasoline stocks high. In their 1998

study, the NPC estimated that there were 247 million barrels of petroleum products held in the tertiary sector, of

which about 45 percent was diesel fuel and distillate fuel

oil and about 25 percent was motor gasoline.14

In the future, as U.S. crude oil production declines, the

transportation and storage system will need to adapt to

the new sources and types of oil being delivered to U.S.

refineries. Some changes which may occur are the addition of pipelines, changes in the use of existing pipelines,

and enlargement of port facilities. Environmental concerns have already led to new regulations for storage facilities and tankers. Pipelines are also likely to feel the

effects of changing environmental regulations that will

require adjustments in the current distribution system.

44 Petroleum: An Energy Profile, 1999

For the most recent data on inter-regional movements of crude oil and petroleum products and storage volumes

of petroleum products by type of storage facility, look for the current issue of the Petroleum Supply Monthly on

the “Petroleum” page of EIA’s website at http://www.eia.doe.gov/. Refinery receipts of crude oil by method of

transportation are published every other year (i.e., 1996, 1998, etc.) in the Petroleum Supply Annual, Volume 1,

also on the “Petroleum” page.

14 National Petroleum Council, Petroleum Storage and Transportation,Volume IV (Washington DC, 1998), p. 1-8.
7. Imports and Exports

Petroleum imports1 play a much larger role in U.S. foreign

trade than petroleum exports, and their role is expected to expand as domestic crude oil supplies diminish. Net imports2

currently account for nearly 5 out of every 10 barrels of crude

oil and petroleum products used in the United States (Figure

7.1) and could account for nearly 7 out of every 10 barrels by

the year 2020.3

As petroleum demand increases, U.S. petroleum refineries

keep pace by processing domestic and imported crude oils to

produce the desired product slate. Refineries respond to

changing demand patterns and changing crude oil sources by

adding or reducing capacity for a given process or altering

utilization levels to adjust output. Or, based upon the nature

and level of demand, refinery distillation and downstream

capacity, and the quality, availability, and price of crude oil

and other feedstocks, refiners and others may opt to import

finished products. Refinery processing of crude oil to satisfy

U.S. demand for gasoline and other light products inevitably

produces other heavier products such as heavy gas oils and

petroleum coke for which there is less domestic demand. To

maximize return on investment, oil companies market these

heavier products at home or abroad. Demand for these fuels

is greater in other parts of the world and significant amounts

are exported.

Historically, government policy has affected petroleum imports and exports. Both import regulations designed to support domestic prices and protect domestic producers, and

export regulations designed to protect domestic supply availability have influenced U.S. petroleum trade.

As early as 1932, the Federal government imposed import

fees on crude oil and refined products.4 The Mandatory Oil

Import Program replaced voluntary import quotas in 1959.

This program, which remained in effect until 1973, generally

restricted imports to a percentage of domestic production.

Price and allocation controls were suspended with deregulation of the oil industry in 1981. Currently, petroleum imports

are subject to the tariffs specified in the Tariff schedules of

the United States and collected by the U.S. Customs Service.

However, the United States-Canada Free Trade Agreement

of 1988 provided for the phaseout of duties on petroleum imports from Canada by 1993. More than 15 percent of U.S. petroleum imports in 1997 came from Canada.

Product export controls authorized under the Emergency Petroleum Allocation Act in 1973 were lifted in October 1981.

Product exports increased substantially after the controls

were lifted.

Imports

In the late 19th century, the U.S. oil industry supplied between 80 and 90 percent of the world’s oil. In the early

1920’s, overseas exploration resulted in discovery of vast

new fields in the Middle East. As low-cost oil from these

new sources began to enter the world market, imports began

to play a major role in U.S. petroleum supply. By 1948, the

United States was importing more petroleum than it exported. The United States has been a “net importer” of crude

oil and petroleum products ever since.

By 1953, gross imports of crude oil and refined products averaged over 1 million barrels per day. Net imports (imports

minus exports) amounted to over 600,000 barrels per day and

accounted for approximately 8 percent of demand in the

United States, already the world’s largest oil consumer. Domestic producers were concerned that competition from foreign oil was lowering prices and forcing them to limit

production. In 1955, Congress amended the 1953 Trade Expansion Act, giving the President virtually unlimited power

to restrict imports if national security were threatened. Despite the establishment of voluntary import quotas in 1957,

imports continued to increase. In 1959, mandatory quotas

were imposed and remained in effect until 1973.5

Meanwhile, five key oil producing nations (Venezuela,

Saudi Arabia, Iran, Iraq, and Kuwait) banded together in

1960 to form the Organization of Petroleum Exporting

Countries (OPEC). Over the next decade eight other countries joined the cartel, which sought to protect the revenues

and market shares of its members as oil demand grew worldwide.

Government wage and price controls instituted throughout

the U.S. economy in 1971 to combat inflation stabilized domestic oil prices below rapidly escalating world prices. This

encouraged the development of foreign oil sources and reduced domestic production.6 Imports nearly doubled between 1970 and 1973, rising to nearly 6.3 million barrels per

day, with crude oil accounting for more than half. Net imPetroleum: An Energy Profile, 1999 45

1 The Energy Information Administration defines imports as the receipt of crude oil and petroleum products into the 50 States and the District of

Columbia from foreign countries, Puerto Rico, the Virgin Islands, and other U.S. possessions and territories.

2 Imports minus exports.

3 Energy Information Administration, Annual Energy Outlook 1999, DOE/EIA-0383(99) Table A11, p. 116.

4 The Internal Revenue Act of 1932 placed import fees on crude oil and certain refined products to encourage domestic refining.

5 Congressional Quarterly, Energy Policy, 2nd ed. (Washington, DC: Congressional Quarterly, 1981), pp.30-31.

6 U.S. Department of Energy, United States Energy Policy, 1980-1988, DOE/S-0068 (October 1988), p. 4.
46 Petroleum: An Energy Profile, 1999
ports averaged more than 6 million barrels per day. OPEC

sources supplied almost 3 million barrels per day (net) of

crude oil and products in 1973, or approximately 17 percent

of total U.S. demand. The growth in imports was due largely

to economic growth, rising personal income, and greater

numbers of automobiles which stimulated demand for oil,

just as domestic production, which had peaked at 9.6 million

barrels per day in 1970, began to decline.

Dependence on OPEC supplies was becoming evident in

other countries as well and led to the first major oil shock.

Oil prices in a sellers’market doubled during 1973. Then, in

response to U.S. support for Israel in the October 1973

Arab-Israeli war, Arab producers reduced production and

implemented an oil embargo against the United States and

other countries. By the spring of 1974, oil prices had climbed

to four times their level at the beginning of the previous year.

In response to these OPEC actions, the President and congress continued the price controls on U.S. crude oil and

adopted a 21-cent-per-barrel crude oil import fee.

Despite rapidly rising prices and a wide range of U.S. efforts

toward energy independence, U.S. reliance on foreign crude

oil continued to grow through the 1970’s. Imports peaked in

1977 at 8.8 million barrels per day; net imports averaged 8.6

million barrels per day, or the equivalent of 47 percent of domestic demand.

After the Iranian revolution in 1978 and 1979, foreign crude

oil prices rose again, providing incentive for domestic exploration and development. Oil from Alaska’s North Slope,

which began moving through the Trans-Alaska Pipeline in

1977, contributed a substantial share to domestic supplies.

New supplies from non-OPEC sources in the Western Hemisphere displaced some OPEC oil. Conservation measures

also began to have some effect. By 1983, gross imports of

crude oil and petroleum products averaged less than 5.1 million barrels per day, 43 percent below their 1977 level. (Exports of Alaskan crude oil and certain refined products

surged in the late 1970’s and early 1980’s, so net imports

dropped even more dramatically.) Although OPEC members supplied 70 percent of U.S. petroleum imports in 1977,

their share continued to shrink until 1985, when OPEC members supplied 36 percent (Figure 7.2).

In an attempt to regain market share and to recover lost

power in the marketplace, OPEC members increased production, flooding the already over-supplied market. This

sent oil prices plunging to between $9 and $11 per barrel by

the summer of 1986. The price collapse had two major effects in the United states: (1) it boosted demand and (2) it

forced domestic producers to curtail drilling. The result was

an increase in imports, especially from OPEC suppliers.7 By

1997, total petroleum net imports had grown to 9.2 million

barrels per day, accounting for 49 percent of U.S. demand,

the highest import dependency level ever recorded.

The Organization of Petroleum Exporting countries (OPEC)

continued to increase in importance as a source of petroleum

imports. By 1997, imports from OPEC members reached

nearly 4.6 million barrels per day, the highest level since

1979 and about two and one-half times the 1985 level. Imports from Venezuela and Saudi Arabia accounted for most

of the increase during this period.

Meanwhile, imported crude oil destined for the Strategic Petroleum Reserve (SPR), which began in 1977, peaked at

256,000 barrels per day in 1981, before falling to only 12,000

barrels per day by 1994. After 1994, imported crude oil was

not used to fill the SPR.

Crude oil accounted for about three-fourths of total petroleum imports during the late 1970’s, before falling to about

two-thirds by the early 1980’s. However, crude oil imports

again gained importance and grew to account for more than

four-fifths of total petroleum imports by 1997. Crude oil imports averaged 8.2 million barrels per day in 1997, with about

46 percent coming from OPEC sources. Non-OPEC sources

provided most of the crude oil imported from 1982 through

1985; however, some OPEC members, especially Saudi Arabia re-emerged as leading suppliers of crude oil to the United

States during this period. Crude oil imports from Saudi Arabia grew steadily until their peak during the 1991 Persian

Gulf War. Ten countries including both OPEC and nonOPEC sources (Kuwait, Saudi Arabia, Gabon, Nigeria,

Venezuela, Angola, Canada, Colombia, Mexico, and Norway) accounted for nearly 9 out of every 10 barrels of crude

oil imported into the United States in 1997 (Figure 7.3).

Since the mid-1980’s, imports of refined products have declined, accounting for slightly more than one-third of total

imports in 1985, to less than one-fifth of total imports by

1997. Most of the major petroleum product imports over this

period have remained relatively consistent, except for residual fuel oil. Since the late 1950’s, when residual accounted

for around 90 percent of refined product imports, its share

has dwindled, while the shares of other products such as motor gasoline, distillate fuel oil, liquefied petroleum gases, and

unfinished oil have generally increased (Table 7.1).

Nearly 54 percent of all refined product imports in 1997

came from only three sources: Venezuela, Canada, and the

Virgin Islands. Algeria and Saudi Arabia were among the

other major suppliers. Moreover, the Virgin Islands was the

leading source of finished motor gasoline, distillate fuel oil,

and unfinished oils.

Most petroleum imports enter the United States through refiners, brokers, and bulk terminals in three major geographic

areas. The Gulf Coast, a major refining center, was the point

of entry for 56 percent of the crude oil imported in 1997. The

East Coast and the Midwest also received large amounts of

crude oil — 18 percent and 20 percent of the total, respectively. Most refined products (56 percent of the total) entered

Petroleum: An Energy Profile, 1999 47

7 U.S. Department of Energy, United States Energy Policy, DOE/S-0068, 1980-1988, pp. 8-9.
48 Petroleum: An Energy Profile, 1999

Year Distillate

Fuel Oil

Jet

Fuel

Liquefied

Petroleum

Gases

Motor

Gasoline

Residual

Fuel Oil

Unfinished

Oils

Other

Products1

Total

Products

1955 12 NA 0 13 417 15 9 466

1960 35 34 4 27 637 45 17 799

1965 36 81 21 28 946 92 27 1,229

1970 147 144 52 67 1,528 108 49 2,095

1975 155 133 112 184 1,223 36 109 1,951

1980 142 80 216 140 939 55 76 1,646

1985 200 39 187 381 510 318 232 1,866

1990 278 108 188 342 504 413 291 2,123

1995 193 106 146 265 187 349 359 1,605

1997 228 91 169 309 194 353 591 1,936

Table 7.1 Petroleum Product Imports by Type, Selected Years 1955-1997

(Thousand Barrels per Day)

1 Includes aviation gasoline, motor gasoline blending components, aviation gasoline blending components, kerosene, petrochemcial feedstocks,

special naphthas, lubricants, wax, asphalt, petroleum coke, pentanes plus, and miscellaneous products.

NA = Not Available.

Note: Totals may not equal sum of components due to independent rounding.

Source: 1955-1995: Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0384(97), Table 5.3; 1997: Energy Information

Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1, Table 20.

0

2

4

6

8

10

12

1980 1982 1984 1986 1988 1990 1992 1994 1996

Year

Million Barrels per Day

Total

Non-OPEC

OPEC

Figure 7.2 U.S. Petroleum Imports by Source, 1980-1997

Source: Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1, and predecessor reports.
the country along the East Coast. The Gulf Coast was the

other major receiving area for product imports (33 percent).

Companies that operate refineries are the leading importers

of crude oil and petroleum products in the United States.

Large integrated oil companies import crude oil almost exclusively for processing in their U.S. refineries. Large independent oil companies are also heavy importers of crude oil,

but import products as well. Smaller refiners tend to import

either refined products exclusively or a mix that is predominantly crude oil. Bulk-terminal operators, brokers, and consumers bring in nearly one-half of the major petroleum

products imported. Despite unused domestic refining capacity, traders and consumers can sometimes obtain products

more economically from foreign sources, if nearby refineries

lack the facilities, location, or distribution system necessary

to serve them at competitive prices. Product imports have established a niche in many high-demand U.S. markets that

may expand in the future, especially in meeting sudden,

short-term demand surges (such as seasonal changes in gasoline and heating oil demand).

Exports

The United States exported 1.0 million barrels per day of

crude oil and petroleum products8 in 1997, matching the record level set in 1993. More than half of all U.S. petroleum

exports are destined for five countries—Japan, Canada,

Petroleum: An Energy Profile, 1999 49

1 to 99

100 to 249

250 to 499

500 and above

Thousand Barrels per Day

Figure 7.3 Sources of U.S. Crude Oil Imports, 1997

Source: Energy Information Administration, Petroleum Supply Annual 1997, DOE/EIA-0340(97)/1.

8 Exports include all shipments of petroleum from the 50 States and the District of Columbia to foreign countries, Puerto Rico, Virgin Islands, and U.S.

possessions and territories.
Mexico, the Republic of Korea, and Spain (Figure7.4). Petroleum coke is the leading petroleum product exported to Japan, accounting for 57 percent of total U.S. petroleum

exports to that country in 1997. Special naphtha was another

major petroleum product exported to Japan. Residual fuel

oil, petroleum coke, crude oil, and jet fuel were the major

U.S. petroleum exports to Canada in 1997. Of these exports,

residual fuel oil and petroleum coke accounted for similar 13

percent shares. Motor gasoline accounted for 43 percent of

the petroleum exported to Mexico in 1997. Liquefied petroleum gases and distillate fuel oil accounted for most of the remainder. Petroleum coke accounts for virtually all of the

petroleum exports to Spain. Crude oil accounted for 67 percent of the U.S. petroleum exports to the Republic of Korea

in 1997.

In the past, various laws restricted petroleum exports. The

Export Administration Acts of 1969, 1979, and 1985 authorized the President, through the Secretary of Commerce, to restrict exports when they would be to the Nation’s detriment.

Export licensing is carried out through the Commerce Department’s Office of Export Administration. In 1973, the

Emergency Petroleum Allocation Act authorized export

controls that included a system of quotas administered

through the Commerce Department’s export licensing procedures. These quotas were in effect until allocation controls

were lifted on October 1981. While petroleum product exports were heavily restricted between 1973 and 1981, they

have been largely unrestricted since that time. Crude oil exports are presently limited to oil delivered from fields under

State waters of Alaska’s Cook Inlet, certain domestically

produced crude oil destined for Canada, and shipments to

U.S. territories, and California crude oil to Pacific Rim countries9

.

Petroleum exports increased steadily from 1975 through

1982, with the export of Alaskan North Slope crude oil to the

Virgin Islands and Puerto Rico accounting for much of the

increase beginning in 1977. After dipping somewhat in the

mid-80’s, petroleum exports have remained near or above

1.0 million barrels per day since 1991.

Crude oil exports peaked in 1980 at 287,000 barrels per day.

By 1997, crude oil exports averaged 108,000 barrels per day,

accounting for about 11 percent of total petroleum exports.

The Republic of Korea received the largest share of total U.S.

crude oil exports, or more than 1 out of ever 3 barrels of crude

oil exported from the United States during 1997.

Product exports increased substantially after allocation controls governing the export of petroleum products were lifted

in October 1981: product exports for 1981 averaged 367,000

barrels per day, and by 1982 they reached 579,000 barrels per

day, more than double the 1980 level of 258,000 barrels per

day. Product exports have averaged more than 600,000 barrels per day since 1986, and reached 896,000 barrels per day

in 1997, when they accounted for more than 89 percent of total petroleum exports.

Heavy products such as residual fuel oil and petroleum coke

are co-products of motor gasoline. When U.S. refineries process crude oil to meet U.S. motor gasoline demand, they necessarily produce heavier fuels as well, often in quantities

greater than required for the domestic market. Foreign demand absorbs the excess.

Petroleum coke is the leading petroleum export product, accounting for about 30 percent of petroleum exports in 1997

(Figure 7.5). Japan, Spain, and Italy are the leading destinations for U.S. exports of this commodity.

Distillate fuel oil is the second most exported product, accounting for 15 percent of total U.S. petroleum product exports. Exports of distillate fuel oil increased dramatically

following the lifting of export controls, to a high of 274,000

barrels per day by 1993. However, by 1997, exports of distillate fuel had dropped to 152,000 barrels per day. Mexico and

Singapore, the Netherlands, and Canada were the main destinations.

The third most exported product in 1997 was motor gasoline,

accounting for nearly 14 percent of total U.S. petroleum

product exports. Mexico was the leading destination for motor gasoline with a nearly 66 percent share of total exports.

While foreign demand is the primary factor determining export levels for the heavier petroleum products, there are other

economic incentives for exporting petroleum products. For

example, shipping costs may be lower for exports than for

domestic transfers because many international water shipments are shorter than domestic transfers. Also, because

50 Petroleum: An Energy Profile, 1999

0 50 100 150 200 250 300 350 400

China

Singapore

Italy

Netherlands

Spain

Rebublic of Korea

Japan

Canada

Mexico

Other

Thousand Barrels per Day

Figure 7.4 U.S. Petroleum Exports by Destination,

1997

Source: Energy Information Administration, Petroleum Supply

Annual 1997, DOE/EIA-0340(97)/1.

9 On December 6, 1991, the U.S. Department of Commerce approved a license to export 25,000 barrels per day of California heavy crude oil (less than

20 degrees API gravity) to Pacific Rim countries for one year.
many U.S. ports cannot accommodate large supertankers,

domestic shipments are often unable to realize the same

economies of scale as international shipments. In addition,

U.S. law requires that commodities transported from one

U.S. port to another be carried in ships built in the United

States or U.S. flag vessels manned by U.S. seamen, making

these shipments more costly than international shipments.

Opposing these incentives to export are foreign restrictions

such as tariffs in the European Economic Community and Japan that render many U.S. refined products too costly for the

market in those countries.

Prices and other market conditions also influence exports.

For example, higher gasoline prices in Europe drew unusually large volumes of motor gasoline exports from the United

States as price increases triggered by the Persian Gulf crisis

coincided with the end of the 1990 summer driving season to

curb domestic demand.

Future exports of petroleum from the United States will depend on economic conditions worldwide and the restrictions

placed on trade both in this country and abroad. The industrialized countries will continue to be the major oil consumers

over the next 20 years. Petroleum use will increase at the

fastest rate in the developing countries, however. The United

States currently exports refined petroleum products to several of the developing countries, with Mexico being the largest destination. In 1997, Mexico received nearly 207 barrels

per day of petroleum products from the United States. The

United States can be expected to continue exporting petroleum products, especially the heavy products used by these

and other countries, because of less emphasis on the heavy

products in this country. Transportation costs, other economic factors, and political events will determine these future export volumes and destinations.

Petroleum: An Energy Profile, 1999 51

0 5 10 15 20 25 30 35

Other

Special Naphthas

Lubricants

Kerosene-Type Jet Fuel

Liquefied Petroleum Gases

Crude Oil

Residual Fuel Oil

Motor Gasoline

Distillate Fuel Oil

Petroleum Coke

Percent

1

1

Includes pentanes plus, other hydrocarbons/oxygenates, motor

gasoline blending components, naphtha-type jet fuel, kerosene, waxes,

asphalt and road oil, and miscellaneous products.

Note: Components do not add to 100 percent due to independent

rounding.

Source: Energy Information Administration, Petroleum Supply

Annual 1997, DOE/EIA-0340(97)/1, Table 28.

Figure 7.5 Exports of Crude Oil and Petroleum

Products, 1997

For the most recent data on U.S. imports and exports of crude oil and petroleum products, look for the current issues of the Weekly Petroleum Status Report and the Petroleum Supply Monthly on the “Petroleum” page of EIA’s

website at http://www.eia.doe.gov/. Historical series are available in the Monthly Energy Review and the Annual Energy Review on the “Historical” page of our website. In addition, company-level imports data are available monthly, also on the “Petroleum” page.
8. Petroleum Marketing

Petroleum companies are a mix of large integrated companies known often as “major oil companies” and smaller “independents.” Integrated oil companies own and operate

establishments in many facets of the industry, from exploration through marketing. The independent companies, although greater in number than the majors, own a smaller

share of the industry. These companies usually specialize in

one particular activity of the oil industry, such as production

or marketing (as independent drilling or exploration contractors or independent service station operators).

The petroleum market can be thought of as two separate but

interdependent markets for crude oil and products in which

the majors, independents, and a host of traders and marketers

cooperate in transferring ownership from producers to consumers. Crude oil ownership is transferred from producers

to refiners by transactions in the crude oil market. Products

refined from crude oil are sold to final consumers in the petroleum products market, where price movements are similar, but not entirely parallel, to those in the crude oil market.

In recent years, the trading of petroleum “futures” has added

a new dimension to both markets.

Crude Oil

Crude Oil Transactions

Refiners are the ultimate consumers of crude oil. Resellers

act as middlemen, purchasing oil from producers and then

selling it to refiners. Oil brokers arrange trades, bringing

buyers and sellers together for a brokering fee. Refiners, resellers, or brokers may import crude oil from foreign sources.

Integrated companies, which operate refineries and produce

their own crude oil, can simply transfer oil from one company department to another. Even integrated companies,

however, often buy and sell crude oil outside the company.

Exchanges are very common methods of transferring crude

oil ownership. For example, if Company A produces crude

oil from fields that are located far from its refinery, that company may exchange its crude oil for that of Company B

whose fields are located closer to Company A’s refinery. If

Company B operates a refinery near Company A’s production field, then the exchange is mutually beneficial, as both

save the cost of transporting their oil. Companies may also

exchange crude oils of different grades or quality to obtain

the kind of oil suitable to their refineries’ needs. Payments

are made to cover location or quality differentials.

Crude oil purchases and exchanges can be accomplished by

long-term contracts or through spot market acquisitions.

Long-term contracts specify the volumes to be delivered and

fix the price for a period of time. Since the middle 1980’s,

more and more crude oil has been bought and sold on the spot

market, where single cargoes of oil are purchased for more

immediate delivery. Buyers and sellers agree on a price at the

same time of sale, which is much closer to the actual delivery

date. Therefore, the “spot” price is usually a better indicator

of current market conditions than long-term contract prices.

Crude Oil Prices

The crude oil market was fairly stable from the late 1940’s

until 1973. Since then, crude oil prices have experienced

changes, reacting to market forces, U.S. government regulations, and world political events (Figure 8.1). In 1973, the

Arab oil embargo presented the world with its first major energy crisis. Crude oil prices rose sharply as Arab producers

cut world supply. The Iranian revolution in 1978 gave the

world oil market its second major shock. In late 1978, an oil

field strike in Iran halted production there. The lack of exports cut world supplies and the price of oil again increased

greatly. When the Iran/Iraq war started in 1980, prices increased again. Ten years later, Iraq’s invasion of Kuwait began another sudden escalation of prices.

In response to crude oil shortages caused by the energy crises

of the 1970’s, mandatory and voluntary conservation programs were initiated to reduce the demand for petroleum

products. These measures included reducing highway speed

limits, lowering temperatures in commercial buildings and

residences, increasing fuel economy of automobiles, and restricting gasoline purchases to certain days and/or minimum

amounts. In the mid-1970’s, the Government instituted a

program which managed the distribution of limited crude oil

and product supplies among refiners. The general effect of

these regulations was to keep the market from responding

normally to supply and demand pressures. Price controls

placed on domestically produced crude oil and refined products in 1971, as part of the Federal Government’s inflation-fighting wage and price control program, held down the

price of domestic crude oil while world oil prices were rising.

When the Government lifted these controls in 1981, domestic oil producers were allowed to raise their prices for the first

time since the early 1970’s, and domestic crude oil prices became more closely aligned with foreign crude oil prices. In

1981, the average cost of domestic crude oil at the wellhead

was $31.77 per barrel, about $10 more per barrel than the

previous year.1

Petroleum: An Energy Profile, 1999 53

1 Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0384(97), Table 5.16
The Organization of Petroleum Exporting Countries (OPEC)

(see Glossary) has influenced world oil prices since it was organized in 1960. Originally created to negotiate production

and pricing matters with the major oil companies that at the

time had large controlling interests in those countries’ supplies, OPEC now tries to keep prices at its target level by setting an upper production limit on its members. OPEC has the

potential to influence oil prices worldwide because its members possess such a great portion of the world’s oil supply.

Although OPEC lost some of its market share in the late

1970’s and early 1980’s, its members still account for nearly

43 percent2 of the world’s production of crude oil and hold

about 67 percent3 of the world’s estimated remaining reserves.

In 1982, world crude oil prices began a downward trend as

demand slackened. Increasing production by non-OPEC

countries, such as Egypt, Mexico, Norway, and the United

Kingdom, combined with the effects of conservation investment in earlier periods created an oversupply of oil on the

world market. When a resurgence in OPEC production began in 1986, crude oil prices plummeted. In the years following the price collapse, prices fluctuated as world oil demand

increased slightly, and OPEC continued to struggle to keep

production within its agreed-upon limits.

On August 2, 1990, Iraq invaded Kuwait, causing crude oil

and product prices to rise suddenly and sharply for the third

time in 17 years. After the United Nations approved an embargo on all crude oil and products originating from either

country, uncertainty about future supplies caused the rapid

price escalation. Between the end of July and August 24,

1990, the world price of crude oil climbed from about $16 per

barrel to more than $28 per barrel. The price escalated further in September, reaching about $36 per barrel.4 By the end

of November, however, as production from other countries

offset the loss of Iraqi and Kuwati oil in world markets, and

fears of a worldwide shortage subsided, petroleum prices stabilized. Refiners paid an average of $21.76 per barrel for imported crude oil in 1990, 20 percent higher than in 1989, but

still well below the average of $37.05 in 1981.5

Petroleum Futures

Unlike contract and spot markets, the futures market is a paper market where contracts for crude oil and some petroleum

products are bought and sold. Successful futures trading began in 1978 when futures contracts for No. 2 heating oil were

first offered on the New York Mercantile Exchange

(NYMEX). NYMEX remains the leader in energy futures

54 Petroleum: An Energy Profile, 1999

$0

$5

$10

$15

$20

$25

$30

$35

$40

1970 1975 1980 1985 1990 1995

Dollars per barrel, current dollars

1981:

Petroleum Price and

Allocation Decontrol

1973:

Arab Oil Embargo

Emergency Petroleum Allocation Act (EPAA)

1974:

Introduction of Unleaded Motor

Gasoline Per Clean Air Act of 1970 (CAA)

1975:

Energy Policy and

Conservation Act (EPCA)

1977:

U.S Department of Energy

Organization Act

1978:

CAFÉ Standards Implemented

Under EPCA

Airlines Deregulation Act

Power Plant and Industrial

Fuel Use Act

U.S. Petroleum Demand Peaks

Iranian Revolution

1985:

Netback Pricing

1986:

Crude Oil

Price Collapses

1989:

Valdez Oil Spill

Phase I RVP

Regulations

Implemented

1990:

CAA Amendments (CAAA)

Persian Gulf Crisis

Oil Pollution Act

1991:

Dissolution

of USSR

1992:

Phase II RVP

Regulations Implemented

CAAA's CO Nonattainment

Program Implemented

Energy Policy Act

Introduction

of RFG

Source: Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0384(97), Table 5.19.

Figure 8.1 Critical Petroleum-Related Events and U.S. Crude Oil Refiner Acquisition Costs, 1970-1997

2 Energy Information Administration, Monthly Energy Review, DOE/EIA-0035(99/02) February 1999, Tables 10.1a and 10.1b.

3 Energy Information Administration, Annual Energy Review, 1997, DOE/EIA-0384(97), Table 11.3.

4 Energy Information Administration, Weekly Petroleum Status Report, DOE/EIA-0208(91-11) March 1, 1991.

5 Energy Information Administration, Annual Energy Review ,1997, DOE-EIA-0384(97), Table 5.19.
trading. Petroleum futures contracts are also traded at the International Petroleum Exchange in London and at the Singapore International Monetary Exchange (SIMEX).

Futures trading of crude oil on NYMEX began in 1983. It is

the most actively traded petroleum commodity in the futures

market. Other products traded include unleaded gasoline,

which NYMEX began trading in 1984, and propane, which

has been traded since 1987. Leaded gasoline was traded on

NYMEX from 1981 to 1986. In 1986 and 1987, futures market activity was expanded with the introduction of options

contracts for crude oil and heating oil. In 1989, options contracts for gasoline were added. Reformulated gasoline, required by EPA in large urban non-complying ozone areas,

has been added to the list of commodities traded on NYMEX.

A futures contract is an agreement between a seller to deliver and a buyer to accept a commodity on a designated date

in the future for a specified price. The contract defines a standard quantity and quality of the product and the point of delivery. On the NYMEX, for example, all crude oil contracts

specify 1,000 barrels of West Texas Intermediate6 crude oil

to be delivered at Cushing, Oklahoma, as a standard. The

price is settled by negotiation when the contract is sold.

One contract can be traded many times before the actual delivery date, each time at a new price. Therefore, the futures

price should approach the market price as it gets closer to the

delivery date. Because the futures market is largely used as a

means of assuring price and availability of future oil supplies, many more contracts are traded than oil is actually delivered.

Futures trades at the exchange are executed by brokers who

are members of the exchange, and act for the actual purchaser/seller. In addition to providing a means for trading

parties to interact, the exchange also guarantees to settle contracts if one of the parties defaults. Part of the reason it can

make this guarantee is that the broker must put up a percentage of the contract’s value (called a margin), which is forfeited if the trader does not fulfill his contract obligations.

The required margin increases if the value of the futures contract decreases, thus increasing the cost of defaulting and

lowering the risk that a trader will default to avoid a loss.

NYMEX conducts petroleum futures trading under regulation by the Commodity Futures Trading Commission.

An options contract gives the trader the right to buy or sell a

futures contract at a later date for a specified price. It is not,

however, an obligation to buy or sell. The right to buy is

known as a “call” option and the right to sell as a “put” option. The option may or may not be exercised depending on

how futures prices change. If an option is not exercised, the

buyer loses a premium paid to the seller.

The futures market succeeds because of contract liquidity

and price uncertainty, which has dominated the oil market

since the early 1970’s. Some traders use the futures market

for speculating on price changes. More often, however, the

futures market is used by producers and consumers to hedge

against uncertainty in price or supply. A hedge is designed to

protect a trader against losses when the price changes to his

disadvantage. It can be accomplished because a hedger

makes counterbalancing (opposite) transactions in the futures market and the cash market (where physical goods are

traded).

Although a significant number of traders in petroleum futures contracts are professional market traders with no interest in oil itself, the number of oil industry participants is large

and growing. Refiners, producers, and marketers are most

likely to use the futures market for hedging. For example, an

oil producer can establish the sales price for oil that will be

produced later, by selling a futures contract. Then, if a drop

in market price causes the value of the oil held for later production to decline, the loss will be borne by the holder of the

futures contract. Likewise, a refiner may want to fix the price

that must be paid for crude oil that is needed in the future, by

buying a futures contract. An increase in the price of crude oil

means a larger amount must be paid to purchase the oil in the

cash market, but the refiner would be able to profit on the resale of the futures contract. Of course, if the price of crude oil

decreases, the refiner will not be able to maximize profits because of obligations on futures contracts. Many companies,

however, are willing to forego some of the potential profits in

order to decrease their risks of loss. Hedging also makes it

easier for companies to plan and budget for the future since

they do not have to worry as much about price changes.

Options contracts can also be used to protect against adverse

price changes. However, because the purchaser is not required to complete the transaction, options traders do not

have to forego all profits during favorable price changes. If,

for example, a refiner has an option to buy a crude oil contract and the price of oil declines, the refiner will buy the

lower priced oil on the cash market but is not obligated to pay

the higher price to the seller of the options contract. Options

trading does have a cost, of course, namely the premium

which must be paid in order to trade.

The volume of oil being traded as futures is very large and

has grown rapidly in the last few years — nearly 24.8 million

crude oil futures contracts and 5.8 million crude oil options

were traded on NYMEX in 1997. The up-to-date price information which is readily available from the exchange can influence price negotiations on the spot market and on

long-term contracts. Nowadays, the prices for crude oil

agreed on in the cash markets are usually tied to the price of a

few “reference” crude oils like West Texas Intermediate, and

the prices for these references are basically determined by

traders in the futures market. Likewise, petroleum product

prices, even for those products not traded in the futures marPetroleum: An Energy Profile, 1999 55

6 West Texas Intermediate (WTI) is a high-quality light, low sulfur crude oil that is used as the U.S. benchmark crude oil; i.e., it serves as the standard

by which other U.S. crude oils are compared.
ket, are often linked to product prices or even crude oil prices

in the futures market.

Petroleum Products

Product Marketing

Unlike crude oil, which is mostly consumed by only one kind

of final user, refined petroleum products are ultimately sold

to a variety of users in the transportation, residential, industrial, commercial, and electric utility sectors of the economy.

Products may be sold directly to end users by the refiner, but

most often the consumer buys from a retailer. Resellers, often defined as wholesale dealers, are the middlemen. They

buy from refiners and sell to other resellers or to retail outlets. Many resellers are also retailers.

Wholesale marketers of petroleum products usually own

and/or operate bulk plants or terminals where large quantities of products are stored and then distributed in smaller lots.

The trucks which transport products from plants to the retailers are often owned and operated by the bulk plant. Bulk

plants may be owned and operated by a major oil company,

owned and operated by independent “jobbers,” or owned by

a major company but operated by independents. Company-operated bulk plants receive and distribute products

supplied by the company and are operated by employees of

the company. Independent operators of company-owned

plants are usually “commission distributors” who sell products on commission. They are committed to selling the company brand at the company’s set price. Independent jobbers

who own, or lease, and operate their own bulk plants, can be

classified as “branded” or “unbranded” depending on

whether they buy from one company and sell under its brand

name or buy from many companies or independent refiners.

Many independent jobbers also participate in retailing activities by owning, or leasing, and operating service stations.

They supply the stations from their bulk plant facilities.

Some trucks are independently owned, i.e., not company

owned or owned by bulk plants. Their owner/operators act as

wholesalers (in cases where trucks supply gasoline to service

stations) or as retailers (in cases where trucks deliver heating

oil to end users). Some independent truck operators work for

distributors on a commission basis.

Service stations, which first began to appear around 1910, remain the predominant retail establishments for marketing

petroleum products. Before service stations, gasoline was

sold in large cans mainly at hardware, grocery, and other general stores. In the 1920’s, as automobile ownership increased, the number of service stations rose rapidly. Many

stations closed during World War II, but after the war the

number increased again until the 1970’s. In the 1970’s and

1980’s, the number of service stations in the United States

declined dramatically, largely due to the closing of stations

which were only marginally profitable. In some areas, one

large station has replaced several smaller ones.

56 Petroleum: An Energy Profile, 1999

Today’s modern service station provides added services including such things as mini-markets, car washes, and

fast food franchises.
Most service station outlets today are not company stations,

i.e., owned or leased by a major oil company and operated by

employees of the oil company. In 1997, companies marketed

about one-fifth of the gasoline they manufactured through

company outlets.7 The remainder was marketed through resellers or directly to end users. Most stations are operated by

independent dealers. Dealers may own or lease their stations, in many cases leasing them from their supplier ( a major company or bulk terminal operator). Dealers are usually

franchisees of a major company, selling only the company

brand, but free to set their own prices. Companies supply

products at wholesale to their dealers and often provide

equipment as well. There are a few service stations which are

completely independent, dealing with more than one supplier to obtain products at the lowest cost and setting the sales

price independently.

History has shown that demand for gasoline is somewhat inelastic, i.e., a large change in price does not bring a proportional change in demand, and that price is not always the

most important factor in a consumer’s decision to buy from a

particular dealer. These realizations have prompted marketers to engage in strategies for creating demand and increasing their market share. Over the years, service stations have

expanded their product lines by adding more automotive services such as mechanical repair services, tire and battery

sales, and car washes. Non-auto products such as convenience foods also have been offered for sale at many service

stations. Games and give-aways have been used at various

times to attract new and repeat business. Major companies

began issuing credit cards to encourage loyalty to their

brand. The introduction of self-service in the 1970’s proved

to be a very successful marketing technique. Self-service

was designed to reduce the service station’s costs and to increase the speed of customer service. According to National

Petroleum News, approximately 90 percent of gasoline sales

are now self-service.

There has been a recent resurgence of attention to marketing

strategies. Faster pumps and more convenient payment systems, for example, are being installed to increase the speed of

service. Attention is also being paid to upgrading the appearance of service stations to a more modern look, with some

companies offering incentives to their dealers to remodel or

rebuild. The number of convenience stores marketing gasoline in addition to other goods is also on the rise.

In many areas of the United States, marketers are installing

payment systems using the latest electronic technology.

Many service stations now accept debit cards in addition to

credit cards. Debit cards are the cards used in automatic

teller machines. When used at a service station, the amount

of the gasoline purchase is deducted from a customer’s

checking account. By associating itself with a whole electronic network, a station can greatly increase its pool of potential customers. Other systems allow cards or cash to be

inserted into the pump for payment.

Product Prices

Petroleum products are sold at different levels in the distribution chain. Class of trade prices (spot, rack, dealer tank

wagon (DTW), and retail) provide information on where in

the distribution chain prices change, and who benefits from

the change (see Figure 8.2). Rack prices are prices paid for

product sold from within the refinery or terminal loading

racks. Only limited distribution and storage costs are included in this price. DTW price represents the prices paid by

retailers for gasoline. Thus, the difference between retail

price (excluding taxes) and DTW price is the money retailers

have available to cover the cost of their operations and return

on investment. The difference between rack price and crude

oil cost represents the dollars refiners have to cover production costs and some storage and distribution costs. DTW

Petroleum: An Energy Profile, 1999 57

Crude Oil Spot West Texas Intermediate

Crude Oil Price

Retail Station Retail Gasoline Price

City Terminal Rack Price

Refinery Refinery Spot Gasoline Price

Pipeline Pipeline Spot Gasoline Price

Figure 8.2 Simplified Gasoline Market Structure

Source: “What Drives Gasoline Prices?,” Energy Information

Administration, Petroleum Marketing Monthly, DOE/EIA-0380 (June

1995), p. xiv.

7 Energy Information Administration, Petroleum Marketing Annual, 1997, DOE/EIA-0487(97), Table 7.
price includes additional marketing, distribution and storage

costs beyond those covered in the rack price.

Class of trade prices include:

Spot Price - Represents a price agreed to by a wholesale

buyer (e.g. distributor) and seller (e.g., refiner) for a single

cargo of product. It can vary significantly day to day.

Rack Price - Refers to the wholesale price charged by

wholesalers at their refineries or company terminals to open

dealers or distributors. Rack prices are usually determined

on a daily basis and are influenced by competitors’ prices as

well as by spot and futures market prices. Rack prices cover

refining costs, including the cost of feedstocks and some

storage costs.

DTW (Dealer Tank Wagon) Price - Is that charged by distributors and refiners to their retailers. These prices include

transportation costs to the dealers’ stations and other business costs (promotions, dealer incentives, etc.) beyond the

basic rack price. DTW prices are established by considering

competitors’ prices and spot, futures, and rack prices.

Retail Price - Is the price paid by the consumer at the gasoline station. It includes the DTW price paid by the retail station for fuel, additional station operation costs, dealer

margins and taxes.

Taxes are also a component of petroleum products prices.

Excise taxes, for example those levied on motor fuels, account for a large fraction of the price. Many consumers are

surprised at the size of the tax component of retail gasoline

prices. As Figure 8.3 shows, taxes add almost 40 cents to the

cost of each gallon of gasoline. In 1997, Federal excise tax

for gasoline accounted for 18.3 cents while State taxes, including local sales taxes, averaged close to 22.0 cents.8 State

taxes vary from 7.5 cents in Georgia to 36 cents in Connecticut. Many times regional price differences are the result of

taxes. Some retailers post the cost of taxes on their pumps, to

inform the public about the importance of taxes in the prices

they’re paying.

Like taxes, manufacturing and marketing costs, which include the retailers’ profit, also tend to change very slowly. In

1997, manufacturing and marketing costs accounted for 34.7

cents per gallon of regular gasoline at retail, while crude oil

costs were 45.3 cents per gallon. Figure 8.4 shows crude oil

and gasoline prices over the past 25 years. By far the most

58 Petroleum: An Energy Profile, 1999

$0.347

Manufacturing &

Marketing

$0.453

Crude Oil

Taxes

$0.399

Retail $1.199/Gallon

Figure 8.3 Components of Retail Regular Gasoline Prices, 1997

Source: Energy Information Administration, Petroleum Marketing Annual 1997, DOE/EIA-0384(97), Tables 1 and 31, and Annual Energy Review,

1997, DOE/EIA-0384(97), Table 5.22.

8 Energy Information Administration, Petroleum Marketing Annual 1997, DOE/EIA-0487(97), Table EN1.
variable component of gasoline prices is the price of crude

oil. But crude oil price changes take time to move through

the distribution chain as shown in Figure 8.2. Generally, a

change in the price of crude oil takes approximately 8 or 9

weeks for the customer to see the full effect of that change on

motor gasoline prices.

The cost of crude oil is a major determinant of the price of refined products, but the price of products also reflects the demand for them. One influence on the demand for products is

the availability of substitutes. In some sectors, like the transportation sector, it is difficult to switch quickly from one fuel

to another without costly and irreversible equipment

changes, but other sectors (primarily industry and electric

utilities) can switch relatively quickly and easily. For example, equipment at large manufacturing plants often can use

either residual fuel oil or natural gas. Often coal and natural

gas can be easily substituted for residual fuel oil at electric

generating plants. For some petroleum products demand is

more sensitive to price than for other products, such as gasoline.

Petroleum: An Energy Profile, 1999 59

0

20

40

60

80

100

120

140

160

1970 1975 1980 1985 1990 1995

Year

Cents per gallon, current dollars

Crude Oil

Retail Regular

Motor Gasoline

Figure 8.4 Prices of Crude Oil and Retail Regular Motor Gasoline, 1970-1997

Source: Energy Information Administration, Annual Energy Review 1997, DOE/EIA-0384(97), Tables 5.19 and 5.22.

For the most recent data on crude oil and petroleum product prices, look for the current issues of the

Weekly Petroleum Status Report and the Petroleum Marketing Monthly on the “Petroleum” page of

EIA’s website at http://www.eia.doe.gov/ . In addition, historical series are available in the Monthly

Energy Review and the Annual Energy Review on the “Historical” page of our website.
Appendix A:

District Descriptions and Maps

The following are the Refining Districts which make up the

Petroleum Administration for Defense (PAD) Districts.

PAD District I

East Coast: District of Columbia and the States of Maine,

New Hampshire, Vermont, Massachusetts, Rhode Island,

Connecticut, New Jersey, Delaware, Maryland, Virginia,

North Carolina, South Carolina, Georgia, Florida, and the

following counties of the State of New York: Cayuga,

Tompkins, Chemung, and all counties east and north thereof.

Also the following counties in the State of Pennsylvania:

Bradford, Sullivan, Columbia, Montour, Northumberland,

Dauphin, York, and all counties east thereof.

Appalachian No. 1: The State of West Virginia and those

parts of the States of Pennsylvania and New York not included in the East Coast District.

Sub-PAD District I

New England: The States of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.

Central Atlantic: The District of Columbia and the States of

Delaware, Maryland, New Jersey, New York, and Pennsylvania.

Lower Atlantic: The States of Florida, Georgia, North

Carolina, South Carolina, Virginia and West Virginia.

PAD District II

Indiana-Illinois-Kentucky: The States of Indiana, Illinois,

Kentucky, Tennessee, Michigan, and Ohio.

Minnesota-Wisconsin-North and South Dakota: The States

of Minnesota,Wisconsin, North Dakota, and South Dakota.

Oklahoma-Kansas-Missouri: The States of Oklahoma,

Kansas, Missouri, Nebraska, and Iowa.

PAD District III

Texas Inland: The State of Texas except the Texas Gulf

Coast District.

Texas Gulf Coast: The following counties of the State of

Texas: Newton, Orange, Jefferson, Jasper, Tyler, Hardin,

Liberty, Chambers, Polk, San Jacinto, Montgomery, Harris,

Galveston, Waller, Fort Bend, Brazoria, Wharton,

Matagorda, Jackson, Victoria, Calhoun, Refugio, Aransas,

San Patricio, Nueces, Kleberg, Kenedy, Willacy, and

Cameron.

Louisiana Gulf Coast: The following parishes of the State

of Louisiana: Vernon, Rapides, Avoyelles, Pointe Coupee,

West Feliciana, East Feliciana, Saint Helena, Tangipahoa,

Washington, and all parishes south thereof. Also the following counties of the State of Mississippi: Pearl River, Stone,

George, Hancock, Harrison, and Jackson. Also the following

counties of the State of Alabama: Mobile and Baldwin.

North Louisiana-Arkansas: The State of Arkansas and

those parts of the States of Louisiana, Mississippi, and Alabama not included in the Louisiana Gulf Coast District.

New Mexico: The State of New Mexico.

PAD District IV

Rocky Mountain: The States of Montana, Idaho, Wyoming,

Utah, and Colorado.

PAD District V

West Coast: The States of Washington, Oregon, California,

Nevada, Arizona, Alaska, and Hawaii.

Petroleum: An Energy Profile, 1999 61
62 Petroleum: An Energy Profile, 1999
Appendix B:

Refinery Processes and Facilities

Physical Separation

Processes

Atmospheric distillation is the first phase of refinery processing and generally follows a preparation process to remove salts, water, and soluble metals. Crude oil vaporizes

when it is heated within the distillation column. As the boiling points of different products (hydrocarbons) are reached,

the vapors condense and are collected in “stream” or “fractions.” Those with the lowest boiling points, the “light” fractions such as fuel gas, light naphtha, and straight-run

gasoline, vaporize at the top of the distillation column. These

products are used as reformer feedstocks, gasoline

blendstocks, and petrochemical feedstocks, or used directly

(e.g., solvents and liquefied petroleum gases). Fractions in

the intermediate boiling ranges, such as gas oil, heavy naphtha, and distillates, are used to produce kerosene, diesel fuel,

distillate fuel oil, jet fuel, blending stocks, and catalytic

cracker feedstocks. Atmospheric “bottoms” have the highest

boiling range and remain after other fractions have been collected. They are used to produce heavy fuel oil, vacuum distillation feedstock, and asphalt.

At atmospheric pressure, “heavy bottoms” decompose into

elemental carbon, coke, and hydrogen before they boil and

vaporize. Vacuum distillation reduces pressure, which lowers the boiling point, allowing further vaporization to occur

with charring or “coking.” Vacuum distillation produces gas

oil to feed downstream processes and heavier oils for lubricant and asphalt production. Vacuum bottoms are processed

in coking units and converted to gasoline components, petroleum coke, and refinery gases or used as fuel.

Two other physical separation processes are mainly used to

make lubricating oils:solvent extraction, in which a solvent

removes one component and leaves behind a less soluble

one; and crystallization, in which cooling allows a component with a high melting point to solidify and separate from

the remaining liquid.

Breakdown Processes

Thermal cracking uses heat and pressure to “crack” or

break down heavy oils and the residuum left from distillation

to increase the yield of lighter products (such as gasoline

components and light fuel oils) and to make coke. Coking, a

form of thermal cracking, uses heat and low pressure to break

down heavy crudes and residual oils into fuel gas, gasoline

blending stocks, distillates and coke. Viscosity Breaking, or

visbreaking, a milder form of thermal cracking, raises the

yield of fuel oil, lowers the viscosity of heavy fuel oil, and

produces small amounts of gasoline blendstocks and gas oil.

Catalytic cracking employs a catalyst to convert vaporized

oil from distillation and other units to high octane gasoline

and other lighter distillates. It produces higher gasoline

yields than thermal cracking and the gasoline produced has

higher octane ratings than gasoline produced using distillation or thermal cracking. Catalytic cracking units operate at

high temperature near atmospheric pressure. As the reaction

takes place, the catalyst is progressively deactivated as carbon (coke) forms, but can be regenerated between cycles by

burning off the coke. In continuous catalytic cracking, the

catalyst cycles between the reactor and regenerating kiln. In

fluid catalytic cracking, the fine powder catalyst behaves as

fluid when vaporized oil bubbles through the particles and

circulates continuously between reaction and regeneration

zones.

Hydrocracking uses hydrogen and a catalyst to reduce

heavy gas oils to gasoline, jet fuel, and diesel fuels. Operating temperatures are lower, and pressures higher, than in

catalytic cracking. Hydrocracking is more effective than catalytic cracking in converting previously cracked gas oils to

lighter products, but it is more expensive.

Change Processes

Catalytic reforming and isomerization are primarily used in

making high octane unleaded gasoline to upgrade hydrocarbon streams whose molecules are the right size but the wrong

configuration. Catalytic reforming upgrades low octane

naphthas to produce high octane gasoline blending stocks. It

also produces high yields of aromatic hydrocarbons used for

petrochemical feedstocks, and generates hydrogen required

for many refinery processes. Isomerization was developed

to produce isobutane from normal butane, for use in the

alkylation process. Isomerization uses platinum catalysts to

Petroleum: An Energy Profile, 1999 63

Note: This Appendix is based on information contained in

U.S. Petroleum Refining,Volume II, published by the National Petroleum Council, (Washington, DC, 1993) Appendix H.
convert low octane normal pentanes to high octane

isopentane for unleaded motor gasoline.

Buildup Processes

Alkylation and polymerization join small, highly volatile,

low octane molecules to form large, less volatile, higher octane molecules. Alkylation is basically the reverse of cracking; it combines small molecule hydrocarbons from catalytic

cracking to form high octane compounds in the gasoline

range for use in high octane unleaded motor gasoline and aviation gasoline.

The polymerization process links short chain molecules together. Although polymer gasolines are somewhat lower in

octane and yields are lower than can be obtained through the

alkylation process, capital and operating costs are lower for

polymerization than for alkylation. As a result, polymerization recovered importance following the Environmental Protection Agency’s (EPA) restriction of the lead content in

gasoline. The process is also important in the petrochemical

industry.

Supporting Operation and

Facilities

• The refinery gas plant extracts alkylation feed and

heavier components from refinery by product gases.

• Hydrodesulfurization is a catalytic process to remove

impurities from liquid petroleum fractions, especially

when their presence would harm the process catalyst. It

reduces sulfur emissions, improves product yields, and

upgrades petroleum fractions into finished products.

Hydrogen required for this process and for other refinery processes such as hydrocracking and isomerization

may be produced in a hydrogen production unit. Either steam reforming of hydrocarbons such as methane

or partial oxidation of heavier hydrocarbons may be

used to produce the hydrogen required.

• Chemical treating removes such impurities as carbon

dioxide, oxidants, and various corrosion compounds

from processing systems.

• Stabilization processes allow controlled distillation to

remove enough light hydrocarbons that the remaining

product has the desired volatility. Solvent treating,

dewaxing, and hydrofinishing change heavy gas oils

produced by vacuum distillation into high quality lubricants. In solvent treating, solvents and “lube” (lubricant) stocks flow against one another in a tower to

remove impurities. Dewaxing uses a solvent to dilute

lube stocks in order to remove the wax that impedes the

flow at normal temperature. After dilution the oil is

chilled to crystallize the wax so that it can be filtered

out. Hydrofinishing uses hydrogen and a catalyst to remove impurities.

• In percolation filtration, lube stock percolates through

a tower filled with fuller’s earth and bauxite to stabilize

its color.

• Propane deasphalting produces “bright stock” lubricating oil from select crude oil in vacuum tower bottoms. Heavy reduced crude is mixed with and dissolves

in propane; the lubricating oil is drawn off with the propane, leaving the asphalt behind.

• Blending various fractions into finished products is the

final step in the refinery operation. In gasoline blending, an automated system meters and mixes into a finished product various components, or “blending

stocks,” from the process unit (e.g., butane, alkylate,

isomerization stock, reformate, catalytic gasoline,

naphtha or straight run gasoline) and various additives.

• The “light ends” recovery unit recaptures light hydrocarbon gases, such as methane, ethane, propane, and butane, some olefins and isobutane. The methane and

ethane are used for refinery fuel. Then olefins and isobutane for alkylation feedstock may be separated from

the recovered propane for liquefied petroleum gases

and normal butane for gasoline blending.

• An acid gas treating system uses absorption in an alkaline solution to remove the “acid gases,” hydrogen sulfide and carbon dioxide, from the “sour gas” produced

in a number of refinery processes, before it can be used

for refinery fuel. The acid gases can then be processed

in a sulfur recovery unit.

• Sour water stripping is used to reduce hydrogen sulfide and ammonia levels in “sour water condensate,” or

water containing sulfides and ammonia, that is produced in various refinery operations.

• Storage tanks for crude oil, intermediate products, and

finished products are necessary to the operation of the

refinery, even though they are not directly involved in

the operation of processing units.

• Steam generation systems provide steam for refinery

processes, generate electric power, and run turbines for

blowers.

• Receiving and distribution systems bring materials,

crude oil, and products into the refinery and distribute

finished products to the consumer. They include

pumps, pipelines, storage tanks, tankers, tank cars, tank

trucks, loading and unloading facilities.

64 Petroleum: An Energy Profile, 1999
• Safety systems include flare and fire control systems.

A flare system consists of pipes to collect gases, devices to remove liquid, and a terminal burner to flare

(burn off) the gases safely. The fire control system includes a separate water system with storage pumps, piping, and water spray devices in process areas; sewer

systems with seals, covers, traps, and baffles; foam systems; fire trucks and other specialized equipment; and

firefighters.

• Environmental protection systems are often incorporated into the refinery processes themselves. Cooling

systems use water and air to remove excess heat. Most

water used by refineries is used for cooling. In some refineries, total recirculation has been achieved through

air cooling and closed systems, greatly reducing the

need for cooling water. Water pollution control systems used distillation to remove chemicals from contaminated water from process systems before the water

is reused in other plant services or sent to the waste

treatment facility and holding ponds. Waste water is

also treated chemically so impurities can be filtered out.

Some refineries have separate basins to segregate storm

water runoff so its flow through the treatment facility

can be kept to manageable levels.

• Air pollution control measures include chemical treatment and other measures to reduce sulfur emissions

during production and scrubbers to remove sulfur from

combustion gases and tail gases (residue gases from a

sulfur recovery unit.) Vapor collection systems, floating tanks roofs, and seals are among the means used to

reduce evaporation during storage. Particulate emissions from catalytic crackers are collected by electrostatic precipitators, scrubbers, and filters.

• Solid waste produced by various pollution control

equipment requires careful handling. Sludge from water treatment facilities is incorporated in landfills. Oily

wastes are deposited in selected sites. Powdery catalysts that contain valuable metals are returned to the

manufacturers for recycling.

Petroleum: An Energy Profile, 1999 65
Petroleum: An Energy Profile, 1999 67

Glossary

Alcohol. The family name of a group of organic chemical

compounds composed of carbon, hydrogen, and oxygen.

The series of molecules vary in chain length and are

composed of a hydrocarbon plus a hydroxyl group;

CH3-(CH2)n-OH (e.g., methanol, ethanol, and tertiary

butyl alcohol).

Alkylate. The product of an alkylation reaction. It usually

refers to the high octane product from alkylation units.

This alkylate is used in blending high octane gasoline.

Alkylation. A refining process for chemically combining

isobutane with olefin hydrocarbons (e.g., propylene,

butylene) through the control of temperature and pressure

in the presence of an acid catalyst, usually sulfuric acid or

hydrofluoric acid. The product, alkylate, an isoparaffin,

has high octane value and is blended with motor and

aviation gasoline to improve the antiknock value of the

fuel.

API Gravity. An arbitrary scale expressing the gravity or

density of liquid petroleum products. The measuring scale

is calibrated in terms of degrees API; it may be calculated

in terms of the following formula:

The higher the API gravity, the lighter the compound.

Light crudes generally exceed 38 degrees API and heavy

crudes are commonly labeled as all crudes with an API

gravity of 22 degrees or below. Intermediate crudes fall in

the range of 22 degrees to 38 degrees API gravity.

Aromatics. Hydrocarbons characterized by unsaturated

ring structures of carbon atoms. Commercial petroleum

aromatics are benzene, toluene, and xylene (BTX).

Asphalt. A dark-brown-to-black cement-like material

containing bitumens as the predominant constituent

obtained by petroleum processing. The definition

includes crude asphalt as well as the following finished

products: cements, fluxes, the asphalt content of

emulsions (exclusive of water), and petroleum distillates

blended with asphalt to make cutback asphalts. The

conversion factor for asphalt is 5.5 barrels per short ton.

ASTM. The acronym for the American Society for Testing

and Materials.

Atmospheric Crude Oil Distillation. The refining process

of separating crude oil components at atmospheric

pressure by heating to temperatures of about 600° to 750°

F (depending on the nature of the crude oil and desired

products) and subsequent condensing of the fractions by

cooling.

Aviation Gasoline (Finished). All special grades of

gasoline for use in aviation reciprocating engines, as given

in ASTM Specification D910 and Military Specification

MIL-G-5572. Excludes blending components which will

be used in blending or compounding into finished aviation

gasoline.

Aviation Gasoline Blending Components. Naphthas

which will be used for blending or compounding into

finished aviation gasoline (e.g., straight-run gasoline,

alkylate, reformate, benzene, toluene, and xylene).

Excludes oxygenates (alcohols, ethers), butane, and

pentanes plus. Oxygenates are reported as other

hydrocarbons, hydrogen, and oxygenates.

Barrel. A volumetric unit of measure for crude oil and

petroleum products equivalent to 42 U.S. gallons. This

measure is used in most statistical reports. Factors for

converting petroleum coke, asphalt, still gas and wax to

barrels are given in the definitions of these products.

Barrels Per Calendar Day. The maximum number of

barrels of input that can be processed during a 24-hour

period after making allowances for the following

limitations:

the capability of downstream facilities to absorb the

output of crude oil processing facilities of a given

refinery. No reduction is made when a planned

distribution of intermediate streams through other than

downstream facilities is part of a refinery’s normal

operation;

the types and grades of inputs to be processed;

the types and grades of products expected to be

manufactured;

the environmental constraints associated with refinery

operations;

the reduction of capacity for scheduled downtime such as

routine inspection, mechanical problems, maintenance,

repairs, and turnaround; and

141.5

sp.gr.60° F/60° F

Degrees API = - 131.5
68 Petroleum: An Energy Profile, 1999

the reduction of capacity for unscheduled downtime such

as mechanical problems, repairs, and slowdowns.

Barrels Per Stream Day. The amount a unit can process

running at full capacity under optimal crude oil and

product slate conditions.

Benzene (C6H6). An aromatic hydrocarbon present in

small proportion in some crude oils and made

commercially from petroleum by the catalytic reforming

of naphthenes in petroleum naphtha. Also made from coal

in the manufacture of coke. Used as a solvent, in

manufacturing detergents, synthetic fibers, and

petrochemicals and as a component of high-octane

gasoline.

Blending Components. See Motor or Aviation Gasoline

Blending Components.

Blending Plant. A facility which has no refining

capability but is either capable of producing finished

motor gasoline through mechanical blending or blends

oxygenates with motor gasoline.

Bonded Petroleum Imports. Petroleum imported and

entered into Customs bonded storage. These imports are

not included in the import statistics until they are: (1)

withdrawn from storage free of duty for use as fuel for

vessels and aircraft engaged in international trade; or (2)

withdrawn from storage with duty paid for domestic use.

BTX. The acronym for the commercial petroleum

aromatics benzene, toluene, and xylene. See individual

categories for definitions.

Bulk Station. A facility used primarily for the storage

and/or marketing of petroleum products which has a total

bulk storage capacity of less than 50,000 barrels and

receives its petroleum products by tank car or truck.

Bulk Terminal. A facility used primarily for the storage

and/or marketing of petroleum products which has a total

bulk storage capacity of 50,000 barrels or more and/or

receives petroleum products by tanker, barge, or pipeline.

Butane (C4H10). A normally gaseous straight-chain or

branch-chain hydrocarbon extracted from natural gas or

refinery gas streams. It includes isobutane and normal

butane and is designated in ASTM Specification D1835

and Gas Processors Association Specifications for

commercial butane.

Isobutane (C4H10). A normally gaseous branch-chain

hydrocarbon. It is a colorless paraffinic gas that boils at a

temperature of 10.9° F. It is extracted from natural gas or

refinery gas streams.

Normal Butane (C4H10). A normally gaseous

straight-chain hydrocarbon. It is a colorless paraffinic

gas that boils at a temperature of 31.1° F. It is extracted

from natural gas or refinery gas streams.

Butylene (C4H8). An olefinic hydrocarbon recovered

from refinery processes.

Captive Refinery Oxygenate Plants. Oxygenate

production facilities located within or adjacent to a

refinery complex.

Catalytic Cracking. The refining process of breaking

down the larger, heavier, and more complex hydrocarbon

molecules into simpler and lighter molecules. Catalytic

cracking is accomplished by the use of a catalytic agent

and is an effective process for increasing the yield of

gasoline from crude oil. Catalytic cracking processes

fresh feeds and recycled feeds.

Fresh Feeds. Crude oil or petroleum distillates which

are being fed to processing units for the first time.

Recycled Feeds. Feeds that are continuously fed back for

additional processing.

Catalytic Hydrocracking. A refining process that uses

hydrogen and catalysts with relatively low temperatures

and high pressures for converting middle boiling or

residual material to high-octane gasoline, reformer charge

stock, jet fuel, and/or high grade fuel oil. The process uses

one or more catalysts, depending upon product output, and

can handle high sulfur feedstocks without prior

desulfurization.

Catalytic Hydrotreating. A refining process for treating

petroleum fractions from atmospheric or vacuum

distillation units (e.g., naphthas, middle distillates,

reformer feeds, residual fuel oil, and heavy gas oil) and

other petroleum (e.g., cat cracked naphtha, coker naphtha,

gas oil, etc.) in the presence of catalysts and substantial

quantities of hydrogen. Hydrotreating includes

desulfurization, removal of substances (e.g., nitrogen

compounds) that deactivate catalysts, conversion of

olefins to paraffins to reduce gum formation in gasoline,

and other processes to upgrade the quality of the fractions.

Catalytic Reforming. A refining process using controlled

heat and pressure with catalysts to rearrange certain

hydrocarbon molecules, thereby converting paraffinic and

naphthenic type hydrocarbons (e.g., low-octane gasoline

boiling range fractions) into petrochemical feedstocks and

higher octane stocks suitable for blending into finished

gasoline. Catalytic reforming is reported in two

categories. They are:
Petroleum: An Energy Profile, 1999 69

Low Pressure. A processing unit operating at less than

225 pounds per square inch gauge (PSIG) measured at

the outlet separator.

High Pressure. A processing unit operating at either

equal to or greater than 225 pounds per square inch gauge

(PSIG) measured at the outlet separator.

Charge Capacity. The input (feed) capacity of the

refinery processing facilities.

Commercial Kerosene-Type Jet Fuel. See

Kerosene-Type Jet Fuel.

Contract Arrangements. Long-term contracts which

specify the volumes of a commodity, such as crude oil, to

be delivered and fix the price for a specified period of time.

Crude Oil (Including Lease Condensate). A mixture of

hydrocarbons that exists in liquid phase in underground

reservoirs and remains liquid at atmospheric pressure after

passing through surface-separating facilities. Included

are lease condensate and liquid hydrocarbons produced

from tar sands, gilsonite, and oil shale. Drip gases are also

included, but topped crude oil (residual oil) and other

unfinished oils are excluded. Liquids produced at natural

gas processing plants and mixed with crude oil are

likewise excluded where identifiable. Crude oil is

considered as either domestic or foreign, according to the

following:

Domestic. Crude oil produced in the United States or

from its “outer continental shelf” as defined in 43 USC

1331.

Foreign. Crude oil produced outside the United States.

Imported Athabasca hydrocarbons (tar sands from

Canada) are included.

Crude Oil Losses. Represents the volume of crude oil

reported by petroleum refineries as being lost in their

operations. These losses are due to spills, contamination,

fires, etc. as opposed to refinery processing losses.

Crude Oil Production. The volume of crude oil produced

from oil reservoirs during given periods of time. The

amount of such production for a given period is measured

as volumes delivered from lease storage tanks (i.e., the

point of custody transfer) to pipelines, trucks, or other

media for transport to refineries or terminals with

adjustments for (1) net differences between opening and

closing lease inventories, and (2) basic sediment and water

(BS&W).

Crude Oil Qualities. Refers to two properties of crude oil,

the sulfur content and API gravity, which affect refinery

processing complexity and product characteristics.

Crude Oil, Refinery Receipts. Receipts of domestic and

foreign crude oil at a refinery. Includes all crude oil in

transit except crude oil in transit by pipeline. Foreign

crude oil is reported as a receipt only after entry through

customs. Crude oil of foreign origin held in bonded

storage is excluded.

Delayed Coking. A process by which heavier crude oil

fractions can be thermally decomposed under conditions

of elevated temperatures and pressure to produce a

mixture of lighter oils and petroleum coke. The light oils

can be processed further in other refinery units to meet

product specifications. The coke can be used either as a

fuel or in other applications such as the manufacturing of

steel or aluminum.

Development Well. A well drilled within the proved area

of an oil or gas reservoir to the depth of a stratigraphic

horizon known to be productive.

Disposition. The components of petroleum disposition

are stock change, crude oil losses, refinery inputs, exports,

and products supplied for domestic consumption.

Distillate Fuel Oil. A general classification for one of the

petroleum fractions produced in conventional distillation

operations. It is used primarily for space heating,

on-and-off-highway diesel engine fuel (including railroad

engine fuel and fuel for agricultural machinery), and

electric power generation. Included are products known

as No. 1, No. 2, and No. 4 fuel oils; No. 1, No. 2, and No. 4

diesel fuels. Distillate fuel oil is reported in the following

sulfur categories: 0.05% sulfur and under, for use in

on-highway diesel engines which could be described as

meeting EPA regulations; and greater than 0.05% sulfur,

for use in all other distillate applications.

No. 1 Distillate. A petroleum distillate which meets the

specifications for No. 1 heating or fuel oil as defined in

ASTM D 396 and/or the specifications for No. 1 diesel

fuel as defined in ASTM Specification D 975 with

distillation temperatures of 420° F at the 10-percent

recovery point and 550° F at the 90-percent recovery

point, and kinematic viscosities between 1.4 and 2.2

centistokes at 100° F.

No. 2 Distillate. A petroleum distillate which meets the

specifications for No. 2 heating or fuel oil as defined in

ASTM D 396 and/or the specifications for No. 2 diesel

fuel as defined in ASTM Specification D 975 with

distillation temperatures of 540° and 640° F at the

90-percent recovery point, and kinematic viscosities

between 2.0 and 4.3 centistokes at 100° F.

No. 4 Fuel Oil. A fuel oil for commercial burner

installations not equipped with preheating facilities. It is

used extensively in industrial plants. This grade is a blend
70 Petroleum: An Energy Profile, 1999

of distillate fuel oil and residual fuel oil stocks that

conforms to ASTM Specification D396 or Federal

Specification VV-F-815C; with minimum and maximum

kinematic viscosities between 5.8 and 26.4 centistokes at

100° F. Also included is No. 4-D, a fuel oil for low and

medium-speed diesel engines that conforms to ASTM

Specification D975.

Electricity (Purchased). Electricity purchased for

refinery operations that is not produced within the refinery

complex.

Ending Stocks. Primary stocks of crude oil and petroleum

products held in storage as of 12 midnight on the last day

of the month. Primary stocks include crude oil or

petroleum products held in storage at (or in) leases,

refineries, natural gas processing plants, pipelines, tank

farms, and bulk terminals that can store at least 50,000

barrels of petroleum products or that can receive

petroleum products by tanker, barge, or pipeline. Crude

oil that is in-transit by water from Alaska, or that is stored

on Federal leases or in the Strategic Petroleum Reserve is

included. Primary Stocks exclude stocks of foreign origin

that are held in bonded warehouse storage.

ETBE (Ethyl tertiary butyl ether) (CH3)3COC2H5. An

oxygenate blend stock formed by the catalytic

etherification of isobutylene with ethanol.

Ethane (C2H6). A normally gaseous straight-chain

hydrocarbon. It is a colorless paraffinic gas that boils at a

temperature of -127.48° F. It is extracted from natural gas

and refinery gas streams.

Ether. A generic term applied to a group of organic

chemical compounds composed of carbon, hydrogen, and

oxygen, characterized by an oxygen atom attached to two

carbon atoms (e.g., methyl tertiary butyl ether).

Ethylene (C2H4). An olefinic hydrocarbon recovered

from refinery processes or petrochemical processes.

Exploratory Well. A well drilled to find and produce oil or

gas in an unproved area; to find a new reservoir in a field

previously found to be productive of oil or gas in another

reservoir; or to extend the limit of a known oil or gas

reservoir.

Exports. Shipments of crude oil and petroleum products

from the 50 States and the District of Columbia to foreign

countries, Puerto Rico, the Virgin Islands, and other U.S.

possessions and territories.

Field. An area consisting of a single reservoir or multiple

reservoirs all grouped on, or related to, the same individual

geological structural feature and/or stratigraphic

condition. There may be two or more reservoirs in a field

that are separated vertically by intervening impervious

strata, or laterally by local geologic barriers, or by both.

Field Area. A geographic area encompassing two or more

pools that have a common gathering and metering system,

the reserves of which are reported as a single unit. This

concept applies primarily to the Appalachian region. (See

Pool)

Field Production. Represents crude oil production on

leases, natural gas liquids production at natural gas

processing plants, new supply of other hydrocarbons/

oxygenates and motor gasoline blending components, and

fuel ethanol blended into finished motor gasoline.

First Purchase (of crude oil). An equity (not custody)

transaction involving an arms-length transfer of

ownership of crude oil associated with the physical

removal of the crude oil from a property (lease) for the

first time. A first purchase normally occurs at the time and

place of ownership transfer where the crude oil volume

sold is measured and recorded on a run ticket or other

similar physical evidence of purchase. The reported cost

is the actual amount paid by the purchaser, allowing for

any adjustments (deductions or premiums) passed on to

the producer or royalty owner.

Flexicoking. A thermal cracking process which converts

heavy hydrocarbons such as crude oil, tar sands bitumen,

and distillation residues into light hydrocarbons.

Feedstocks can be any pumpable hydrocarbons including

those containing high concentrations of sulfur and metals.

Fluid Coking. A thermal cracking process utilizing the

fluidized-solids technique to remove carbon (coke) for

continuous conversion of heavy, low-grade oils into

lighter products.

Fresh Feed Input. Represents input of material (crude

oil, unfinished oils, natural gas liquids, other

hydrocarbons and oxygenates or finished products) to

processing units at a refinery that is being processed

(input) into a particular unit for the first time.

Examples:

(1) Unfinished oils coming out of a crude oil distillation unit which are input into a catalytic cracking

unit are considered fresh feed to the catalytic cracking unit.

(2) Unfinished oils coming out of a catalytic cracking

unit being looped back into the same catalytic

cracking unit to be reprocessed are not considered

fresh feed.
Petroleum: An Energy Profile, 1999 71

Fuel Ethanol (C2H5OH). An anhydrous denatured

aliphatic alcohol intended for gasoline blending as

described in Oxygenates definition.

Fuels Solvent Deasphalting. A refining process for

removing asphalt compounds from petroleum fractions,

such as reduced crude oil. The recovered stream from this

process is used to produce fuel products.

Futures Contract. A promise to deliver a specified

quantity of a specified commodity at a specified place,

price, and time in the future.

Gas Oil. A liquid petroleum distillate having a viscosity

intermediate between that of kerosene and lubricating oil.

It derives its name from having originally been used in the

manufacture of illuminating gas. It is now used to produce

distillate fuel oils and gasoline.

Gasohol. A blend of finished motor gasoline and alcohol

(generally ethanol but sometimes methanol), limited to 10

percent by volume of alcohol.

Gasoline Blending Components. Naphthas which will be

used for blending or compounding into finished aviation

or motor gasoline (e.g., straight-run gasoline, alkylate,

reformate, benzene, toluene, and xylene). Excludes

oxygenates (alcohols, ethers), butane, and pentanes plus.

Gross Input to Atmospheric Crude Oil Distillation Units.

Total input to atmospheric crude oil distillation units.

Includes all crude oil, lease condensate, natural gas plant

liquids, unfinished oils, liquefied refinery gases, slop oils,

and other liquid hydrocarbons produced from tar sands,

gilsonite, and oil shale.

Heavy Gas Oil. Petroleum distillates with an approximate

boiling range from 651° to 1000° F.

Hydrocracking. (See Catalytic Hydrocracking)

Hydrogen. The lightest of all gases, occurring chiefly in

combination with oxygen in water; exists also in acids,

bases, alcohols, petroleum, and other hydrocarbons.

Hydrotreating. (See Catalytic Hydrotreating)

Idle Capacity. The component of operable capacity that is

not in operation and not under active repair, but capable of

being placed in operation within 30 days; and capacity not

in operation but under active repair that can be completed

within 90 days.

Imported Crude Oil Burned As Fuel. The amount of

foreign crude oil burned as a fuel oil, usually as residual

fuel oil, without being processed as such. Imported crude

oil burned as fuel includes lease condensate and liquid

hydrocarbons produced from tar sands, gilsonite, and oil

shale.

Imports. Receipts of crude oil and petroleum products

into the 50 States and the District of Columbia from

foreign countries, Puerto Rico, the Virgin Islands, and

other U.S. possessions and territories.

Indicated Additional Reserves of Crude Oil. Quantities

of crude oil (other than proved reserves) which may

become economically recoverable from existing

productive reservoirs through the applicaton of improved

recovery techniques using current technology. These

recovery techniques may:

1. Already be installed in the reservoir, but their effects

are not yet known to the degree necessary to classify the

additional reserves as proved;

2. Be installed in another similar reservoir, where the

results of that installation can be used to estimate the

indicated additional reserves.

Indicated additional reserves are not included in proved

reserves due to their uncertain economic recoverability.

When economic recoverability is demonstrated, the

indicated additional reserves must be transferred to

proved reserves as positive revisions.

Isobutane. See Butane.

Isobutylene (C4H8). An olefinic hydrocarbon recovered

from refinery processes or petrochemical processes.

Isohexane (C6H14). A saturated branch-chain

hydrocarbon. It is a colorless liquid that boils at a

temperature of 156.2° F.

Isomerization. A refining process which alters the

fundamental arrangement of atoms in the molecule

without adding or removing anything from the original

material. Used to convert normal butane into isobutane

(C4), an alkylation process feedstock, and normal pentane

and hexane into isopentane (C5) and isohexane (C6),

high-octane gasoline components.

Isopentane. See Natural Gasoline and Isopentane.

Kerosene. A petroleum distillate that has a maximum

distillation temperature of 401° F at the 10-percent

recovery point, a final boiling point of 572° F, and a

minimum flash point of 100° F. Included are the two

grades designated in ASTM D3699: No. 1-K and No. 2-K,

and all grades of kerosene called range or stove oil.

Kerosene is used in space heaters, cook stoves, and water
72 Petroleum: An Energy Profile, 1999

heaters and is suitable for use as an illuminant when

burned in wick lamps.

Kerosene-Type Jet Fuel. A quality kerosene product with

a maximum distillation temperature of 400° F at the

10-percent recovery point and a final maximum boiling

point of 572° F. The fuel is designated in ASTM

Specification D1655 and Military Specifications

MIL-T-5624R and MIL-T-83133D (Grades JP-5 and

JP-8). A relatively low-freezing point distillate of the

kerosene type used primarily for turbojet and turboprop

aircraft engines.

Commercial. Kerosene-type jet fuel intended for use in

commercial aircraft.

Military. Kerosene-type jet fuel intended for use in

military aircraft.

Lease Condensate. A natural gas liquid recovered from

gas well gas (associated and non-associated) in lease

separators or natural gas field facilities. Lease condensate

consists primarily of pentanes and heavier hydrocarbons.

Light Gas Oils. Liquid petroleum distillates heavier than

naphtha, with an approximate boiling range from 401° F to

650° F.

Liquefied Petroleum Gases (LPG). Ethane, ethylene,

propane, propylene, normal butane, butylene, isobutane,

and isobutylene produced at refineries or natural gas

processing plants, including plants that fractionate raw

natural gas plant liquids.

Liquefied Refinery Gases (LRG). Liquefied petroleum

gases fractionated from refinery or still gases. Through

compression and/or refrigeration, they are retained in the

liquid state. The reported categories are ethane/ethylene,

propane/propylene, normal butane/butylene, and

isobutane/isobutylene. Excludes still gas.

Lubricants. A substance used to reduce friction between

bearing surfaces or as process materials either

incorporated into other materials used as processing aids

in the manufacturing of other products, or as carriers of

other materials. Petroleum lubricants may be produced

either from distillates or residues. Other substances may

be added to impart or improve certain required properties.

Do not include byproducts of lubricating oil refining such

as aromatic extracts derived from solvent extraction or tars

derived from deasphalting. “Lubricants” includes all

grades of lubricating oils from spindle oil to cylinder oil

and those used in greases. Reporting categories include:

Paraffinic. Includes all grades of bright stock and

neutrals with a Viscosity Index > 75.

Naphthenic. Includes all lubricating oil base stocks with

a Viscosity Index < 75.

Note: The criterion for categorizing the lubricants is

based solely on the Viscosity Index of the stocks and is

independent of crude sources and type of processing

used to produce the oils.

Exceptions: Lubricating oil base stocks that have been

historically classified as naphthenic or paraffinic by a

refiner may continue to be so categorized irrespective of

the Viscosity Index criterion.

Example:

(1) Unextracted paraffinic oils that would not meet

the Viscosity Index test.

Merchant Oxygenate Plants. Oxygenate production

facilities that are not associated with a petroleum refinery.

Production from these facilities is sold under contract or

on the spot market to refiners or other gasoline blenders.

Methanol (CH3OH). A light, volatile alcohol intended

for gasoline blending as described in Oxygenate

definition.

Middle Distillates. A general classification of refined

petroleum products that includes distillate fuel oil and

kerosene.

Military Kerosene-Type Jet Fuel. See Kerosene-Type

Jet Fuel.

Miscellaneous Products. Includes all finished products

not classified elsewhere (e.g., petrolatum, lube refining

byproducts (aromatic extracts and tars), absorption oils,

ram-jet fuel, petroleum rocket fuels, synthetic natural gas

feedstocks, and specialty oils).

Motor Gasoline (Finished). A complex mixture of

relatively volatile hydrocarbons, with or without small

quantities of additives, that has been blended to form a

fuel suitable for use in spark-ignition engines. Motor

gasoline, as given in ASTM Specification D-4814 or

Federal Specification VV-G-1690C, includes a range in

distillation temperatures from 122 degrees to 158 degrees

F at the 10-percent recovery point and from 365 degrees to

374 degrees F at the 90-percent recovery point. “Motor

gasoline” includes reformulated gasoline, oxygenated

gasoline, and other finished gasoline. Blendstock is

excluded until blending has been completed.

Reformulated Gasoline. Gasoline formulated for use in

motor vehicles, the composition and properties of which

meet the requirements of the reformulated gasoline

regulations promulgated by the U.S. Environmental
Petroleum: An Energy Profile, 1999 73

Protection Agency under Section 211K of the Clean Air

Act. Includes oxygenated fuels program reformulated

gasoline (OPRG). Excludes reformulated gasoline

blendstock for oxygenate blending (RBOB).

Oxygenated Gasoline. Gasoline formulated for use in

motor vehicles that has an oxygen content of 1.8 percent

or higher, by weight. Includes gasohol. Excludes

reformulated gasoline, oxygenated fuels program

reformulated gasoline (OPRG) and reformulated

gasoline blendstock for oxygenate blending (RBOB).

OPRG. “Oxygenated Fuels Program Reformulated

Gasoline” is reformulated gasoline which is intended for

use in an oxygenated fuels program control period.

Other Finished or Conventional Gasoline. Motor

gasoline not included in the oxygenated or reformulated

gasoline categories. Excludes reformulated gasoline

blendstock for oxygenate blending (RBOB).

Motor Gasoline Blending. Mechanical mixing of motor

gasoline blending components and oxygenates to produce

finished motor gasoline. Mechanical mixing of finished

motor gasoline with motor gasoline blending components

or oxygenates which results in increased volumes of

finished motor gasoline, and/or changes in the

classification of finished motor gasoline (e.g., other

finished motor gasoline mixed with MTBE to produce

oxygenated motor gasoline), is considered motor gasoline

blending.

Motor Gasoline Blending Components. Naphthas which

will be used for blending or compounding into finished

motor gasoline (e.g., straight-run gasoline, alkylate,

reformate, benzene, toluene, xylene) and includes

reformulated gasoline blendstock for oxygenate blending

(RBOB). Excludes oxygenates (alcohols, ethers), butane,

and pentanes plus. Oxygenates are reported as individual

components and included in the total for other

hydrocarbons, hydrogens, and oxygenates.

MTBE (Methyl tertiary butyl ether) (CH3)3COCH3. An

ether intended for gasoline blending as described in

Oxygenate definition.

Naphtha. A generic term applied to a petroleum fraction

with an approximate boiling range between 122° and 400°

F.

Naphtha Less Than 401° F. See Petrochemical

Feedstocks.

Naphtha-Type Jet Fuel. A fuel in the heavy naphtha

boiling range. ASTM Specification D1655 specifies for

this fuel maximum distillation temperatures of 290° F at

the 20-percent recovery point and 470° F at the 90-percent

point, meeting Military Specification MIL-T-5624L

(Grade JP-4). JP-4 is used for turbojet and turboprop

aircraft engines, primarily by the military. Excludes

ram-jet and petroleum rocket fuels.

Natural Gas. A mixture of hydrocarbons and small

quantities of various nonhydrocarbons existing in the

gaseous phase or in solution with crude oil in underground

reservoirs.

Natural Gas Field Facility. A field facility designed to

process natural gas produced from more than one lease for

the purpose of recovering condensate from a stream of

natural gas; however, some field facilities are designed to

recover propane, normal butane, pentanes plus, etc., and to

control the quality of natural gas to be marketed.

Natural Gas Plant Liquids. Natural gas liquids recovered

from natural gas in gas processing plants, and in some

situations, from natural gas field facilities. Natural gas

liquids extracted by fractionators are also included. These

liquids are defined according to the published

specifications of the Gas Processors Association and the

American Society for Testing and Materials and are

classified as follows: ethane, propane, normal butane,

isobutane, and pentanes plus.

Natural Gas Processing Plant. A facility designed (1) to

achieve the recovery of natural gas liquids from the stream

of natural gas which may or may not have been processed

through lease separators and field facilities, and (2) to

control the quality of the natural gas to be marketed.

Cycling plants are classified as gas processing plants.

Natural Gasoline and Isopentane. A mixture of

hydrocarbons, mostly pentanes and heavier, extracted

from natural gas, that meets vapor pressure, end-point,

and other specifications for natural gasoline set by the Gas

Processors Association. Includes isopentane which is a

saturated branch-chain hydrocarbon, (C5H12), obtained

by fractionation of natural gasoline or isomerization of

normal pentane.

Net Receipts. The difference between total movements

into and total movements out of each PAD District by

pipeline, tanker, and barge.

Normal Butane. See Butane.

OPEC. The acronym for the Organization of Petroleum

Exporting Countries, that have organized for the purpose

of negotiating with oil companies on matters of oil

production, prices and future concession rights. Current

members are Algeria, Indonesia, Iran, Iraq, Kuwait,

Libya, Nigeria, Qatar, Saudi Arabia, United Arab

Emirates, and Venezuela. The Neutral Zone between

Kuwait and Saudi Arabia is considered part of OPEC.
74 Petroleum: An Energy Profile, 1999

Prior to January 1, 1993, Ecuador was a member of OPEC.

Prior to January 1995, Gabon was a member of OPEC.

OPRG. “Oxygenated Fuels Program Reformulated

Gasoline” is reformulated gasoline which is intended for

use in an oxygenated fuels program control area during an

oxygenated fuels program control period.

Operable Capacity. The amount of capacity that, at the

beginning of the period, is in operation; not in operation

and not under active repair, but capable of being placed in

operation within 30 days; or not in operation but under

active repair that can be completed within 90 days.

Operable capacity is the sum of the operating and idle

capacity and is measured in barrels per calendar day or

barrels per stream day.

Operating Capacity. The component of operable capacity

that is in operation at the beginning of the period.

Operable Utilization Rate. Represents the utilization of

the atmospheric crude oil distillation units. The rate is

calculated by dividing the gross input to these units by the

operable refining capacity of the units.

Operating Utilization Rate. Represents the utilization of

the atmospheric crude oil distillation units. The rate is

calculated by dividing the gross input to these units by the

operating refining capacity of the units.

Other Finished. See Motor Gasoline (Finished).

Other Hydrocarbons. Materials received by a refinery

and consumed as a raw material. Includes hydrogen, coal

tar derivatives, gilsonite, and natural gas received by the

refinery for reforming into hydrogen. Natural gas to be

used as fuel is excluded.

Other Oils Equal To or Greater Than 401° F. See

Petrochemical Feedstocks.

Other Oxygenates. Other aliphatic alcohols and aliphatic

ethers intended for motor gasoline blending (e.g.,

isopropyl ether (IPE) or n-propanol).

Outer Continental Shelf (OCS). U.S. offshore waters that

are under Federal domain.

Oxygenated Gasoline. See Motor Gasoline (Finished).

Oxygenates. Any substance which, when added to

gasoline, increases the amount of oxygen in that gasoline

blend. Through a series of waivers and interpretive rules,

the Environmental Protection Agency (EPA) has

determined the allowable limits for oxygenates in

unleaded gasoline. The “Substantially Similar”

Interpretive Rules (56 FR (February 11, 1991)) allows

blends of aliphatic alcohols other than methanol and

aliphatic ethers, provided the oxygen content does not

exceed 2.7 percent by weight. The “Substantially Similar”

Interpretive Rules also provides for blends of methanol up

to 0.3 percent by volume exclusive of other oxygenates,

and butanol or alcohols of a higher molecular weight up to

2.75 percent by weight. Individual waivers pertaining to

the use of oxygenates in unleaded gasoline have been

issued by the EPA. They include:

Fuel Ethanol. Blends of up to 10 percent by volume

anhydrous ethanol (200 proof) (commonly referred to as

the “gasohol waiver”).

Methanol. Blends of methanol and gasoline-grade

tertiary butyl alcohol (GTBA) such that the total oxygen

content does not exceed 3.5 percent by weight and the

ratio of methanol to GTBA is less than or equal to 1. It is

also specified that this blended fuel must meet ASTM

volatility specifications (commonly referred to as the

“ARCO” waiver).

Blends of up to 5.0 percent by volume methanol with a

minimum of 2.5 percent by volume cosolvent alcohols

having a carbon number of 4 or less (i.e., ethanol,

propanol, butanol, and/or GTBA). The total oxygen must

not exceed 3.7 percent by weight, and the blend must

meet ASTM volatility specifications as well as phase

separation and alcohol purity specifications (commonly

referred to as the “DuPont” waiver).

MTBE (Methyl tertiary butyl ether). Blends up to 15.0

percent by volume MTBE which must meet the ASTM

D4814 specifications. Blenders must take precautions

that the blends are not used as base gasolines for other

oxygenated blends (commonly referred to as the “Sun”

waiver).

Pentanes Plus. A mixture of hydrocarbons, mostly

pentanes and heavier, extracted from natural gas. Includes

isopentane, natural gasoline, and plant condensate.

Persian Gulf. The countries that comprise the Persian

Gulf are: Bahrain, Iran, Iraq, Kuwait, Qatar, Saudi Arabia,

and the United Arab Emirates.

Petrochemical Feedstocks. Chemical feedstocks derived

from petroleum principally for the manufacture of

chemicals, synthetic rubber, and a variety of plastics. The

categories reported are “Naphtha Less Than 401° F” and

“Other Oils Equal To or Greater Than 401° F.”

Naphtha Less Than 401° F. A naphtha with a boiling

range of less than 401° F that is intended for use as a

petrochemical feedstock.
Petroleum: An Energy Profile, 1999 75

Other Oils Equal To or Greater Than 401° F. Oils with a

boiling range equal to or greater than 401° F that are

intended for use as a petrochemical feedstock.

Petroleum Administration for Defense (PAD) Districts.

Geographic aggregations of the 50 States and the District

of Columbia into five districts by the Petroleum

Administration for Defense in 1950. These districts were

originally defined during World War II for purposes of

administering oil allocation.

Petroleum Coke. A residue, the final product of the

condensation process in cracking. This product is

reported as marketable coke or catalyst coke. The

conversion factor is 5 barrels per short ton.

Marketable Coke. Those grades of coke produced in

delayed or fluid cokers which may be recovered as

relatively pure carbon. This “green” coke may be sold as

is or further purified by calcining.

Catalyst Coke. In many catalytic operations (e.g.,

catalytic cracking) carbon is deposited on the catalyst,

thus deactivating the catalyst. The catalyst is reactivated

by burning off the carbon, which is used as a fuel in the

refining process. This carbon or coke is not recoverable

in a concentrated form.

Petroleum Products. Petroleum products are obtained

from the processing of crude oil (including lease

condensate), natural gas, and other hydrocarbon

compounds. Petroleum products include unfinished oils,

liquefied petroleum gases, pentanes plus, aviation

gasoline, motor gasoline, naphtha-type jet fuel,

kerosene-type jet fuel, kerosene, distillate fuel oil,

residual fuel oil, petrochemical feedstocks, special

naphthas, lubricants, waxes, petroleum coke, asphalt, road

oil, still gas, and miscellaneous products.

Pipeline (Petroleum). Crude oil and product pipelines

used to transport crude oil and petroleum products

respectively, (including interstate, intrastate, and

intracompany pipelines) within the 50 States and the

District of Columbia.

Plant Condensate. One of the natural gas liquids, mostly

pentanes and heavier hydrocarbons, recovered and

separated as liquids at gas inlet separators or scrubbers in

processing plants.

Pool. In general, a reservoir. In certain situations a pool

may consist of more than one reservoir. (See Field Area)

Processing Gain. The volumetric amount by which total

output is greater than input for a given period of time. This

difference is due to the processing of crude oil into

products which, in total, have a lower specific gravity than

the crude oil processed.

Processing Loss. The volumetric amount by which total

refinery output is less than input for a given period of time.

This difference is due to the processing of crude oil into

products which, in total, have a higher specific gravity

than the crude oil processed.

Product Supplied, Crude Oil. Crude oil burned on leases

and by pipelines as fuel.

Production Capacity. The maximum amount of product

that can be produced from processing facilities.

Products Supplied. Approximately represents

consumption of petroleum products because it measures

the disappearance of these products from primary sources,

i.e., refineries, natural gas processing plants, blending

plants, pipelines, and bulk terminals. In general, product

supplied of each product in any given period is computed

as follows: field production, plus refinery production,

plus imports, plus unaccounted for crude oil, (plus net

receipts when calculated on a PAD District basis), minus

stock change, minus crude oil losses, minus refinery

inputs, minus exports.

Propane (C3H8). A normally gaseous straight-chain

hydrocarbon. It is a colorless paraffinic gas that boils at a

temperature of -43.67° F. It is extracted from natural gas

or refinery gas streams. It includes all products designated

in ASTM Specification D1835 and Gas Processors

Association Specifications for commercial propane and

HD-5 propane.

Propylene (C3H6). An olefinic hydrocarbon recovered

from refinery processes or petrochemical processes.

Proved Reserves of Crude Oil. Proved reserves of crude

oil as of December 31 of a given year are the estimated

quantities of all liquids defined as crude oil, which

geological and engineering data demonstrate with

reasonable certainty to be recoverable in future years from

known reservoirs under existing economic and operating

conditions.

Reservoirs are considered proved if economic

producibility is supported by actual production or

conclusive formation tests (drill stem or wire line), or if

economic producibility is supported by core analyses

and/or electric or other log interpretations. The area of an

oil reservoir considered proved includes (1) that portion

delineated by drilling and defined by gas-oil and/or

oil-water contacts, if any; and (2) the immediately

adjoining portions not yet drilled, but which can be

reasonably judged as economically productive on the

basis of available geological and engineering data. In the
76 Petroleum: An Energy Profile, 1999

absence of information on fluid contacts, the lowest

known structural occurrence of hydrocarbons is

considered to be the lower proved limit of the reservoir.

Volumes of crude oil placed in underground storage are

not to be considered proved reserves.

Reserves of crude oil which can be produced

economically through application of improved recovery

techniques (such as fluid injection) are included in the

“proved” classification when successful testing by a pilot

project, or the operation of an installed program in the

reservoir, provides support for the engineering analysis

on which the project or program was based.

Estimates of proved crude oil reserves do not include the

following: (1) oil that may become available from known

reservoirs but is reported separately as “indicated

additional reserves”; (2) natural gas liquids (including

lease condensate); (3) oil, the recovery of which is

subject to reasonable doubt because of uncertainty as to

geology, reservoir characteristics, or economic factors;

(4) oil that may occur in undrilled prospects; and (5) oil

that may be recovered from oil shales, coal, gilsonite, and

other such sources. It is not necessary that production,

gathering or transportation facilities be installed or

operative for a reservoir to be considered proved.

Proved Reserves of Natural Gas Liquids. Proved reserves

of natural gas liquids as of December 31 of a given year are

those volumes of natural gas liquids (including lease

condensate) demonstrated with reasonable certainty to be

separable in the future from proved natural gas reserves,

under existing economic and operating conditions.

RBOB. “Reformulated Gasoline Blendstock for

Oxygenate Blending” is a motor gasoline blending

component which, when blended with a specified type and

percentage of oxygenate, meets the definition of

reformulated gasoline.

Refiner Acquisition Cost. The cost of crude oil to the

refiner, including transportation and fees. The composite

cost is the weighted average of domestic and imported

crude oil costs.

Refinery. An installation that manufactures finished

petroleum products from crude oil, unfinished oils, natural

gas liquids, other hydrocarbons, and oxygenates.

Refinery Capacity Utilization. (See Operable

Utilization Rate and Operating Utilization Rate)

Refinery Input, Crude Oil. Total crude oil (domestic plus

foreign) input to crude oil distillation units and other

refinery processing units (cokers, etc.).

Refinery Input, Total. The raw materials and

intermediate materials processed at refineries to produce

finished petroleum products. They include crude oil,

products of natural gas processing plants, unfinished oils,

other hydrocarbons and oxygenates, motor gasoline and

aviation gasoline blending components and finished

petroleum products.

Refinery Production. Petroleum products produced at a

refinery or blending plant. Published production of these

products equals refinery production minus refinery input.

Negative production will occur when the amount of a

product produced during the month is less than the amount

of that same product that is reprocessed (input) or

reclassified to become another product during the same

month. Refinery production of unfinished oils, and motor

and aviation gasoline blending components appear on a

net basis under refinery input.

Refinery Yield. Refinery yield (expressed as a

percentage) represents the percent of finished product

produced from input of crude oil and net input of

unfinished oils. It is calculated by dividing the sum of

crude oil and net unfinished input into the individual net

production of finished products. Before calculating the

yield for finished motor gasoline, the input of natural gas

liquids, other hydrocarbons and oxygenates, and net input

of motor gasoline blending components must be

subtracted from the net production of finished motor

gasoline. Before calculating the yield for finished

aviation gasoline, input of aviation gasoline blending

components must be subtracted from the net production of

finished aviation gasoline.

Reformulated Gasoline. See Motor Gasoline

(Finished).

Reseller. A firm (other than a refiner) that carries on the

trade or business of purchasing refined petroleum

products and reselling them to purchasers other than

ultimate consumers; e.g., retailers at the gasoline service

stations.

Reseller/Retailer. A firm (other than a refiner) that carries

on the trade or business activities of both a reseller and a

retailer; i.e., purchasing refined petroleum products and

reselling them to purchasers who may be either ultimate or

other than ultimate consumers.

Reserve Additions. Consist of adjustments, net revisions,

extensions to old reservoirs, new reservoir discoveries in

old fields, and new field discoveries.

Reserves. (See Proved Reserves)

Reserves Changes. Positive and negative revisions,

extensions, new reservoir discoveries in old fields, and
Petroleum: An Energy Profile, 1999 77

new field discoveries, which occurred during a given year.

Reserves Extensions. The reserves credited to a reservoir

because of enlargement of its proved area. Normally the

ultimate size of newly discovered fields, or newly

discovered reservoirs in old fields, is determined by wells

drilled in years subsequent to discovery. When such wells

add to the proved area of a previously discovered reservoir,

the increase in proved reserves is classified as an

extension.

Reserves Revisions. Changes to prior year-end proved

reserves estimates, either positive or negative, resulting

from new information other than an increase in proved

acreage (extension). Revisions include increases of

proved reserves associated with the installation of

improved recovery techniques or equipment. They also

include correction of prior report year arithmetical or

clerical errors and adjustments to prior year-end

production volumes to the extent that these alter reported

prior year reserves estimates.

Reservoir. A porous and permeable underground

formation containing an individual and separate natural

accumulation of producible hydrocarbons (oil and/or gas)

which is confined by impermeable rock or water barriers

and is characterized by a single natural presure system.

Residual Fuel Oil. The heavier oils that remain after the

distillate fuel oils and lighter hydrocarbons are distilled

away in refinery operations and that conform to ASTM

Specification D396. Included are No. 5, a residual fuel oil

of medium viscosity; Navy Special, for use in

steam-powered vessels in government service and in shore

power plants; No. 6, which includes Bunker C fuel oil, and

is used for commercial and industrial heating, electricity

generation and to power ships.

Residuum. Residue from crude oil after distilling off all

but the heaviest components, with a boiling range greater

than 1000° F.

Retailer. A firm (other than a refiner, reseller, or

reseller/retailer) that carries on the trade or business of

purchasing refined petroleum products and reselling them

to ultimate consumers.

Road Oil. Any heavy petroleum oil, including residual

asphaltic oil used as a dust pallative and surface treatment

on roads and highways. It is generally produced in six

grades from 0, the most liquid, to 5, the most viscous.

Rotary Rig. A machine, used for drilling wells, that

employs a rotating tube attached to a bit for boring holes

through rock.

Sales for Resale. Sales of refined petroleum products to

purchasers who are other-than-ultimate consumers;

wholesale sales.

Sales to End Users. Sales made directly to the consumer

of the product. Includes bulk consumers, such as

agriculture, industry, and utilities, as well as residential

and commercial consumers.

Shell Storage Capacity. The design capacity of a

petroleum storage tank which is always greater than or

equal to working storage capacity.

Special Naphthas. All finished products within the

naphtha boiling range that are used as paint thinners,

cleaners, or solvents. These products are refined to a

specified flash point. Special naphthas include all

commercial hexane and cleaning solvents conforming to

ASTM Specification D1836 and D484, respectively.

Naphthas to be blended or marketed as motor gasoline or

aviation gasoline, or that are to be used as petrochemical

and synthetic natural gas (SNG) feedstocks are excluded.

Spot Price. A transaction price concluded “on the spot”,

that is, on a one-time, prompt basis to sell or buy one

shipment of a commodity, such as crude oil.

Steam (Purchased). Steam, purchased for use by a

refinery, that was not generated from within the refinery

complex.

Still Gas (Refinery Gas). Any form or mixture of gases

produced in refineries by distillation, cracking, reforming,

and other processes. The principal constituents are

methane, ethane, ethylene, normal butane, butylene,

propane, propylene, etc. Still gas is used as a refinery fuel

and a petrochemical feedstock. The conversion factor is 6

million BTU’s per fuel oil equivalent barrel.

Stock Change. The difference between stocks at the

beginning of the month and stocks at the end of the month.

A negative number indicates a decrease in stocks and a

positive number indicates an increase in stocks.

Stocks, Crude Oil. Crude oil and lease condensate held at

refineries, in pipelines, at pipeline terminals, and on

leases.

Stocks, Primary. Stocks of crude oil or petroleum

products held in storage at (or in) leases, refineries, natural

gas processing plants, pipelines, tank farms, and bulk

terminals. Crude oil that is in transit from Alaska, or that is
78 Petroleum: An Energy Profile, 1999

stored on Federal leases or in the Strategic Petroleum

Reserve, is included. Excluded are stocks of foreign

origin that are held in bonded warehouse storage.

Strategic Petroleum Reserve (SPR). Petroleum stocks

maintained by the Federal Government for use during

periods of major supply interruption.

Sulfur. A yellowish nonmetallic element, sometimes

known as “brimstone”.

Supply. The components of petroleum supply are field

production, refinery production, imports, and net receipts

when calculated on a PAD District basis.

TAME (Tertiary amyl methyl ether)

(CH3)2(C2H5)COCH3. An oxygenate blend stock formed

by the catalytic etherification of isoamylene with

methanol.

Tank Farm. An installation used by gathering and trunk

pipeline companies, crude oil producers, and terminal

operators (except refineries) to store crude oil.

Tanker and Barge. Vessels that transport crude oil or

petroleum products. Data are reported for movements

between PAD Districts; from a PAD District to the Panama

Canal; or from the Panama Canal to a PAD District.

TBA (Tertiary butyl alcohol) (CH3)3COH. An alcohol

primarily used as a chemical feedstock, a solvent or

feedstock for isobutylene production for MTBE; produced

as a co-product of propylene oxide production or by direct

hydration of isobutylene.

Thermal Cracking. A refining process in which heat and

pressure are used to break down, rearrange, or combine

hydrocarbon molecules. Thermal cracking includes gas

oil, visbreaking, fluid coking, delayed coking, and other

thermal cracking processes (e.g., flexicoking). See

individual categories for definition.

Toluene (C6H5CH3). Colorless liquid of the aromatic

group of petroleum hydrocarbons, made by the catalytic

reforming of petroleum naphthas containing methyl

cyclohexane. A high-octane gasoline-blending agent,

solvent, and chemical intermediate, base for TNT.

Ultimate Recovery Appreciation. The commonly

observed increase overtime of the sum of cumulative

production on a specific day and the estimate of proved

reserves on that same day. Also known as “reserves

growth.”

Unaccounted for Crude Oil. Represents the arithmetic

difference between the calculated supply and the

calculated disposition of crude oil. The calculated supply

is the sum of crude oil production plus imports minus

changes in crude oil stocks. The calculated disposition of

crude oil is the sum of crude oil input to refineries, crude

oil exports, crude oil burned as fuel, and crude oil losses.

Undiscovered Recoverable Resources (crude oil and

natural gas). Those economic resources of crude oil and

natural gas, yet undiscovered, that are estimated to exist in

favorable geologic settings.

Unfinished Oils. Includes all oils requiring further

processing, except those requiring only mechanical

blending. Includes naphthas and lighter oils, kerosene and

light gas oils, heavy gas oils, and residuum. See individual

categories for definition.

Unfractionated Streams. Mixtures of unsegregated

natural gas liquid components excluding those in plant

condensate. This product is extracted from natural gas.

United States. The United States is defined as the 50

States and the District of Columbia.

Vacuum Distillation. Distillation under reduced pressure

(less the atmospheric) which lowers the boiling

temperature of the liquid being distilled. This technique

with its relatively low temperatures prevents cracking or

decomposition of the charge stock.

Visbreaking. A thermal cracking process in which heavy

atmospheric or vacuum-still bottoms are cracked at

moderate temperatures to increase production of distillate

products and reduce viscosity of the distillation residues.

Wax. A solid or semi-solid material consisting of a

mixture of hydrocarbons obtained or derived from

petroleum fractions, or through a Fischer-Tropsch type

process, in which the straight chained paraffin series

predominates. This includes all marketable wax, whether

crude or refined, with a congealing point (ASTM D 938)

between 100 and 200° F and a maximum oil content

(ASTM D 3235) of 50 weight percent. The conversion

factor is 280 pounds per 42 U.S. gallons per barrel.

Well. A hole drilled for the purpose of finding or

producing crude oil or natural gas or providing services

related to the production of crude oil or natural gas. Wells

are classified as oil wells, gas wells, dry holes,

stratigraphic or core tests, or service wells.

Working Storage Capacity. The difference in volume

between the maximum safe fill capacity and the quantity

below which pump suction is ineffective (bottoms).
Petroleum: An Energy Profile, 1999 79

Xylene (C6H4(CH3)2). Colorless liquid of the aromatic

group of hydrocarbons made the catalytic reforming of

certain naphthenic petroleum fractions. Used as

high-octane motor and aviation gasoline blending agents,

solvents, chemical intermediates. Isomers are

metaxylene, orthoxylene, paraxylene.