Source: U.S. Energy Information Administration
Shale in the United States 2016
Over the past decade, the combination of horizontal drilling and hydraulic fracturing has provided access to large volumes of oil and natural gas that were previously uneconomic to produce from low permeability geological formations composed of shale, sandstone, and carbonate (e.g., limestone). Shale is a fine-grained sedimentary rock that forms from the compaction of silt and clay-size mineral particles. Black shale contains organic material that can generate oil and natural gas, and that can also trap the generated oil and natural gas within its pores.
Where are shale gas and oil resources found?
Shale oil and natural gas resources are found in shale formations that contain significant accumulations of natural gas and/or oil. The Barnett Shale in Texas has been producing natural gas for more than a decade. Information gained from developing the Barnett Shale provided the initial technology template for developing other shale plays in the United States. Another important shale gas play is the Marcellus Shale in the eastern United States. While the Barnett and Marcellus formations are well-known shale gas plays in the United States, more than thirty U.S. states overlie shale formations.
Within an individual shale play, geophysicists and geologists identify suitable well locations in areas that have the greatest potential to produce commercial volumes of natural gas and oil. These areas are identified using rock core samples and geophysical and seismic technologies to generate maps of the subsurface hydrocarbon resources in a shale formation.
Shale gas, tight gas, and tight oil
The oil and natural gas industry generally distinguishes between three categories of low-permeability formations:
- Shale natural gas
- Tight natural gas
- Tight oil (can be produced from shale or other low-permeability reservoirs)
- Shale natural gas
Large-scale natural gas production from shale began around 2000, when shale gas production became a commercial reality in the Barnett Shale located in north-central Texas. The production of Barnett Shale natural gas was pioneered by the Mitchell Energy and Development Corporation. During the 1980s and 1990s, Mitchell Energy experimented with alternative methods of hydraulically fracturing the Barnett Shale. By 2000, the company had developed a hydraulic fracturing technique that produced commercial volumes of shale gas. As the commercial success of the Barnett Shale became apparent, other companies started drilling wells in this formation so that by 2005, the Barnett Shale was producing almost half a trillion cubic feet (Tcf) of natural gas per year. As natural gas producers gained confidence in their ability to profitably produce natural gas in the Barnett Shale, with additional confirmation provided by well results in the Fayetteville Shale in northern Arkansas, producers started developing other shale formations, including the Haynesville in eastern Texas and north Louisiana, the Woodford in Oklahoma, the Eagle Ford in southern Texas, and the Marcellus and Utica shales in northern Appalachia.
Tight Natural Gas
The identification of tight natural gas as a separate production category began with the passage of the Natural Gas Policy Act of 1978 (NGPA), which established tight natural gas as a separate wellhead natural gas pricing category that was permitted to obtain unregulated market-determined prices. The tight natural gas category was designed to give producers an incentive to produce high-cost natural gas resources when U.S. natural gas resources were believed to be increasingly scarce.
As a result of the NGPA tight natural gas price incentive, these resources have been in production since the early 1980s, primarily from low-permeability sandstones and carbonate formations, with a small production volume coming from eastern Devonian shale. With the full deregulation of wellhead natural gas prices and the repeal of the associated Federal Energy Regulatory Commission (FERC) regulations, tight natural gas no longer had a specifically defined meaning, but generically still pertains to natural gas produced from low-permeability sandstone and carbonate reservoirs.
Notable tight natural gas formations include, but are not confined to Clinton, Medina, and Tuscarora formations in Appalachia Berea sandstone in Michigan Bossier, Cotton Valley, Olmos, Vicksburg, and Wilcox Lobo along the Gulf Coast Granite Wash and Atoka formations in the Midcontinent Canyon formation in the Permian Basin Mesa Verde and Niobrara formations in multiple the Rocky Mountain basins.
Tight Oil
In the United States, the oil and natural gas industry typically refers to tight oil production rather than shale oil production. The industry uses the term tight oil production because it is a more encompassing term with respect to the different geologic formations producing oil at any particular well. Tight oil is produced from low-permeability sandstones, carbonates (e.g., limestone), and shale formations. The oil and natural gas industry’s colloquial use of the term tight oil is rather recent and does not have a specific technical, scientific, or geologic definition.
The U.S. Energy Information Administration (EIA) has adopted the convention of using the term tight oil to refer to all resources, reserves, and production associated with low-permeability formations that produce oil, including that associated with shale formations.
Notable tight oil formations include, but are not confined to Bakken and Three Forks formations in the Williston Basin Eagle Ford, Austin Chalk, Buda; Woodbine formations along the Gulf Coast Spraberry, Wolfcamp, Bone Spring, Delaware, Glorieta; Yeso formations in the Permian Basin Niobrara formation, although located in multiple Rocky Mountain basins, is primarily producing oil in the Denver-Julesburg Basin.
The United States has access to significant shale resources. In the Annual Energy Outlook 2014, EIA estimated that the United States has approximately 610 Tcf of technically recoverable shale natural gas resources and 59 billion barrels of technically-recoverable tight oil resources. As a result, the United States is ranked second globally after Russia in shale oil resources.
Who are the major players supplying the world oil market?
The world oil market is complex. Governments and private companies play various roles in moving oil from producers to consumers. Government-owned national oil companies (NOCs) control most of the world’s proved oil reserves (75 percent in 2014) and oil production (58 percent in 2014). International oil companies (IOCs), which are often stockholder-owned corporations, make up the balance of global oil reserves and production. Proved oil reserves consist of the amount of oil in a given area, known with reasonable certainty, that current technology can recover cost effectively. Worldwide proved oil reserves in 2014 were almost 1.7 trillion barrels, and global oil production averaged roughly 93.2 million barrels a day.
There are different types of oil companies
There are three types of companies that supply crude oil to the global market. Each type of company has different operational strategies and production-related goals:
International oil companies (IOCs): These companies, which include ExxonMobil, BP, and Royal Dutch Shell, are entirely investor owned and primarily seek to increase their shareholder value. As a result, IOCs tend to make investment decisions based on economic factors. These companies typically move quickly to develop and produce the oil resources available to them and sell their output in the global market. Although these producers are affected by the laws of the countries in which they produce oil, all decisions are ultimately made in the interest of the company and its shareholders, not in the interest of a government.
National oil companies (NOCs): These companies operate as an extension of a government or a government agency, and they include Saudi Aramco (Saudi Arabia), Pemex (Mexico), the China National Petroleum Corporation (CNPC), and Petróleos de Venezuela S.A. (PdVSA). These companies support government programs financially and sometimes strategically. These companies often provide fuels to domestic consumers at a lower price than the fuels they provide to the international market. These companies do not always have the incentive, means, or intention to develop their reserves at the same pace as investor owned international oil companies. Because of the diverse objectives of their supporting governments, these NOCs pursue goals that are not necessarily market oriented. The goals of these companies often include employing citizens, furthering a government’s domestic or foreign policies, generating long-term revenue to pay for government programs, and supplying inexpensive domestic energy. All NOCs belonging to members of the Organization of the Petroleum Exporting Countries (OPEC) fall into this category.
NOCs with strategic and operational autonomy: The NOCs in this category function as corporate entities and do not operate as an extension of the government of their country. This category includes Petrobras (Brazil) and Statoil (Norway). These companies often balance profit-oriented concerns and the objectives of their country with the development of their corporate strategy. Although these companies are driven by commercial concerns, they may also take into account their nation’s goals when making investment or other strategic decisions.
In 2014, 100 companies produced 82 percent of the world’s oil. NOCs accounted for 58 percent of global oil production.
OPEC members seek to work together to influence world oil supplies
OPEC is a group that includes some of the world’s most oil-rich countries (see OPEC member countries in the “Did you know?” box). Together, these countries controlled approximately 73 percent of the world’s total proved oil reserves in 2014, and they produced 39 percent of the world’s total oil supply that year. Each OPEC country has at least one NOC, but most also allow international oil companies to operate within their borders.
OPEC seeks to manage the oil production of its member countries by setting crude oil output targets for each member except for Iraq, for which there is no current target. The track record of compliance with OPEC quotas is mixed because production decisions are ultimately in the hands of the individual member countries.
In general, there are three main factors that determine OPEC’s market power, or how effectively the organization can influence oil prices:
- How unwilling or unable consumers are to move away from using oil;
- How competitive non-OPEC producers become as the price of oil increases; and
- How efficiently OPEC producers can supply oil compared with non-OPEC producers.
OPEC’s oil exports represented about 56 percent of the total seaborne crude oil traded internationally in 2014, according to data from Lloyd’s List Intelligence tanker tracking service. The difference between market demand and oil supplied by non-OPEC sources is often referred to as the call on OPEC. Saudi Arabia, the largest oil producer within OPEC and the world’s largest oil exporter, historically has had the largest share of the world’s spare production capacity. As a whole, OPEC maintains the world’s entire spare capacity for oil production. It is generally not cost-effective for international oil companies to develop and maintain idle spare production capacity, because the IOC business model maximizes revenue by continuing to produce oil as long as the price of selling that commodity is higher than the cost of getting an additional barrel of oil to market.
EIA defines spare capacity as the volume of oil production that can be brought online within thirty days and sustained for at least ninty days. Spare capacity can also be thought of as the difference between a country’s current oil production and its maximum oil production capacity. Should a supply disruption occur, oil producers can use spare capacity to moderate increases in world oil prices by boosting production to offset lost oil supplies.
What is the role of coal in the United States?
The United States has the world’s largest estimated recoverable reserves of coal, and it is a net exporter of coal. In 2014, U.S. coal mines produced about one billion short tons of coal, the first increase in annual coal output in three years. More than 90 percent of the coal produced in the United States was used by U.S. power plants to generate electricity. Although coal has been the largest source of electricity generation in the United States for more than sixty years, its annual share of total net generation declined from nearly 50 percent in 2007 to 39 percent in 2014.
Coal is an abundant U.S. resource
The United States is home to the largest estimated recoverable reserves of coal in the world. The country has enough estimated recoverable reserves of coal to last more than 200 years based on current production levels. Coal is produced in 25 states that are located in three major coal-producing regions.
In 2014, approximately 70 percent of U.S. coal production originated in five states:
- Wyoming (396 million short tons)
- West Virginia (112 million short tons)
- Kentucky (77 million short tons)
- Pennsylvania (62 million short tons)
- Illinois (58 million short tons)
Most U.S. coal is used to generate electricity
About 93 percent of the coal consumed in the United States is used for generating electricity. The United States has about 1,300 coal-fired electricity generating units in operation at almost 560 plants across the country. Together, these power plants consumed more than 851 million short tons of coal to generate about 39 percent of the electricity produced in the United States during 2014.
Although coal-fired generation still holds the largest share among all fuel sources used to generate electricity, its use has declined since 2007 because of a combination of slow growth in electricity demand, strong price competition from natural gas, increased use of renewable energy sources, and new environmental regulations that have added to the cost of using coal. See related article—Today in Energy, July 31, 2015.
Although the share of total net electricity generated from coal in the United States is expected to decrease by 2040, coal is still expected to remain an important fuel for generating electricity in the United States absent policies designed to reduce emissions of carbon dioxide and other greenhouse gases. However, the implementation of new policies to limit carbon dioxide emissions from power generation could change the outlook for the use of coal to generate electricity.
In addition to its role in generating electricity, coal also has industrial applications. Coal is used in cement production and coke conversion for the smelting of iron ore at blast furnaces used to make steel. A small amount of coal is also burned to heat commercial, military, and institutional facilities, and an even smaller amount of coal is used to heat homes.
The United States exports coal to other countries
Between 2000 and 2014, about 6.5 percent of the coal produced in the United States, on average each year, was exported to other countries. In 2014, the share of U.S. coal production exported was 9.7 percent, totaling 97.3 million short tons. However, the overall volume of coal exports in 2014 declined by about 17 percent from 117.7 million short tons in 2013.
Europe and Asia continue to be the top destinations for U.S. coal exports. Coal exports come in two forms:
- Metallurgical coal, which is usually used for steel production; and
- Steam coal, which is used for electricity generation and in industrial applications for the production of steam and direct heat.
The United States exported more metallurgical coal than steam coal in 2014. Brazil (7.5 million short tons) was the largest importer of U.S. metallurgical coal, and the Netherlands (6.7 million short tons) was the largest importer of U.S. steam coal.
The United States also imports coal (about 11.3 million short tons in 2014) with most of that coal coming from Colombia. The operators of some coal-fired electric generating units along the U.S. Gulf and Atlantic coasts find it cheaper to import coal than to have domestic coal transported by rail or barge from coal-producing regions in the United States.
Coal is a relatively inexpensive fuel
Although some natural gas-fired power plants are more efficient at generating electricity than coal plants, in the past, the cost of fuel to generate one kilowatthour of electricity from natural gas had typically been higher than that of coal. However, coal began losing its price advantage over natural gas for electricity generation in some parts of the country in 2009, particularly in the eastern United States. Increasing natural gas production from U.S. shale basins helped reduce the price of natural gas, making it more competitive for use in generating electricity. See related article—Today in Energy, October 7, 2015.
Environmental effects of using coal
When coal is burned it produces several types of emissions that adversely affect the environment and human health. Coal emits sulfur dioxide, nitrogen oxide, heavy metals (such as mercury and arsenic), and acid gases (such as hydrogen chloride), which have been linked to acid rain, smog, and other environmental and health-related concerns. Coal also emits carbon dioxide, the greenhouse gas most responsible for climate change. In 2014, coal accounted for about one-third of the energy-related carbon dioxide emissions from the United States.
Side by side pie charts showing U.S. Energy Consumption by Major Fuel Type, 2014 and Resulting U.S. Energy-Related Carbon Dioxide Emissions by Fuel Type, 2014
Outlook for future coal use
The economics of burning coal have changed now that the U.S. government has adopted regulations that restrict or otherwise control carbon dioxide (CO2) emissions, which require coal-fired power plant operators to either incur costs to retrofit power plants or to receive less revenue because of lower levels of operation.
In August 2015, the U.S. Environmental Protection Agency (EPA) approved the final rule of the Clean Power Plan (CPP). The CPP is intended to reduce CO2 emissions at existing coal-fired power plants 32 percent below 2005 levels by 2030. Retirements of coal-fired power plants are expected to increase in response to the implementation of the CPP.
In January 2014, the EPA issued a revised new source performance standard proposal for CO2 emissions that requires new coal-fired power plants to limit emissions to 1,100 pounds of CO2 per megawatthour. The proposed emission limit would effectively require new coal-fired electric generating units to use carbon capture and sequestration technologies to reduce emissions of CO2 by approximately 50 percent.
In March 2013, the EPA finalized the Mercury and Air Toxics Standards (MATS) to reduce emissions of mercury and other air toxics from new and existing coal- and oil-fired electric generating units. Power plants are responsible for more mercury emissions than any other man-made source. The standards were challenged in court, but they were upheld by a federal appeals court in April 2014.
Separately, recent efforts to control nitrogen oxide (NOx) and sulfur dioxide (SO2) emissions from power plants could also have an effect on the use of coal in electricity generation. The EPA’s Cross-State Air Pollution Rule (CSAPR), finalized in July 2011, seeks to reduce SO2 and NOx emissions from power plants in 28 states. The rule was challenged, but in April 2014, the U.S. Supreme Court upheld the CSAPR requirements.
The major energy sources consumed in the United States are petroleum (oil), natural gas, coal, nuclear energy, and renewable energy. The major user sectors of these energy sources are residential and commercial buildings, industry, transportation, and electric power. The pattern of energy use varies widely by sector. For example, petroleum provides 92 percent of the energy used for transportation, but only provides about 1 percent of the energy used to generate electric power. Understanding the relationships between the different energy sources and their uses provides insights into many important energy issues now and in the future.
