Natural Gas and the Environment
Energy Information Administration
Natural Gas 1998: Issues and Trends 49
Currently, natural gas represents 24 percent of the energy consum
ed in the United States. The Energy Information
Administration (EIA) Annual Energy Outlook 1999 projects that this figure will increase to about 28 percent by 2020
under the reference case as consumption of natural gas is projected to increase to 32.3 trillion cubic feet. In
addition, a recent EIA Service Report, Impacts of the Kyoto Protocol on U.S. Energy Markets and Economic
Activity, indicates that the use of natural gas could be even 6 to 10 percent higher in 2020 if the United States
adopts the Kyoto Protocol’s requirement to reduce carbon emissions by 7 percent from their 1990 levels by the
2008–2012 time period, without other changes in laws, regulations, and policies. These increases are expected
because emissions of greenhouse gases are much lower with the consumption of natural gas relative to other fossil
fuel consumption. For instance:
ü Natural gas, when burned, emits lower quantities of greenhouse gases and criteria pollutants per unit of energy
produced than do other fossil fuels. This occurs in part because natural gas is more easily fully combusted,
and in part because natural gas contains fewer impurities than any other fossil fuel. For example, U.S. coal
contains 1.6 percent sulfur (a consumption-weighted national average) by weight. The oil burned at electric
utility power plants ranges from 0.5 to 1.4 percent sulfur. Diesel fuel has less than 0.05 percent, while the
current national average for motor gasoline is 0.034 percent sulfur. Comparatively, natural gas at the burner
tip has less than 0.0005 percent sulfur compounds.
ü The amount of carbon dioxide produced for an equivalent amount of heat production varies substantially
among the fossil fuels, with natural gas producing the least. On a carbon-equivalent basis, energy-related
carbon dioxide emissions accounted for 83.8 percent of U.S. anthropogenic greenhouse gas emissions in
1997. For the major fossil fuels, the amounts of carbon dioxide produced for each billion Btu of heat energy
extracted are: 208,000 pounds for coal, 164,000 pounds for petroleum products, and 117,000 pounds for
natural gas.
Other aspects of the development and use of natural gas need to be considered as well in looking at the
environmental consequences related to natural gas. For example:
ü The major constituent of natural gas, methane, also directly contributes to the greenhouse effect through
venting or leaking of natural gas into the atmosphere. This is because methane is 21 times as effective in
trapping heat as is carbon dioxide. Although methane emissions amount to only 0.5 percent of U.S. emissions
of carbon dioxide, they account for about 10 percent of the greenhouse effect of U.S. emissions.
ü A major transportation-related environmental advantage of natural gas is that it is not a source of toxic spills.
But, because there are about 300,000 miles of high-pressure transmission pipelines in the United States and
its offshore areas, there are corollary impacts. For instance, the construction right-of-way on land commonly
requires a width of 75 to 100 feet along the length of the pipeline; this is the area disturbed by trenching, soil
storage, pipe storage, vehicle movement, etc. This area represents between 9.1 and 12.1 acres per mile of
pipe which is, or has been, subject to intrusion.
Natural gas is seen by many as an important fuel in initiatives to address environmental concerns. Although natural
gas is the most benign of the fossil fuels in terms of air pollution, it is less so than nonfossil-based energy sources
such as renewables or nuclear power. However, because of its lower costs, greater resources, and existing
infrastructure, natural gas is projected to increase its share of energy consumption relative to all other fuels, fossil
and nonfossil, under current laws and regulations.
2. Natural Gas and the Environment
The vast majority of U.S. energy use comes from the global warming and certain public health risks. To address
combustion of fossil hydrocarbon fuels. This unavoidably these health and environmental concerns, the United States
results in a degree of air, land, and water pollution, and the has many laws and regulations in place that are designed to
production of greenhouse gases that might contribute to control and/or reduce pollution. In the United States,
Energy Information Administration
50 Natural Gas 1998: Issues and Trends
natural gas use is projected to increase nearly 50 percent by ü Particulates. The nongaseous criteria pollutant
2020.1 This is because North American natural gas
resources are considered both plentiful and secure, are
expected to be competitively priced, and their increased use
can be effective in reducing the emission of pollutants.
While the use of natural gas does have environmental
consequences, it is attractive because it is relatively cleanburning.
This chapter discusses many environmental
aspects related to the use of natural gas, including the
environmental impact of natural gas relative to other fossil
fuels and some of the potential applications for increased
use of natural gas. On the other hand, the venting or leaking
of natural gas into the atmosphere can have a significant
effect with respect to greenhouse gases because methane,
the principal component of natural gas, is much more
effective in trapping these gases than carbon dioxide. The
exploration, production, and transmission of natural gas, as
well, can have adverse effects on the environment. This
chapter addresses the level and extent of some of these
impacts on the environment.
Air Pollutants and Greenhouse
Gases
The Earth’s atmosphere is a mixture primarily of the gases
nitrogen and oxygen, totaling 99 percent; nearly 1 percent
water; and very small amounts of other gases and
substances, some of which are chemically reactive. With
the exception of oxygen, nitrogen, water, and the inert
gases, all constituents of air may be a source of concern
owing either to their potential health effects on humans,
animals, and plants, or to their influence on the climate.
As mandated by The Clean Air Act (CAA), which was last
amended in 1990, the Environmental Protection Agency
(EPA) regulates “criteria pollutants” that are considered
harmful to the environment and public health:
ü Gases. The gaseous criteria pollutants are carbon
monoxide, nitrogen oxides, volatile organic
compounds,2 and sulfur dioxide (Figure 20). These are
reactive gases that in the presence of sunlight
contribute to the formation of ground level ozone,
smog, and acid rain.
particulate matter consists of metals and substances
such as pollen, dust, yeast, mold, very tiny organisms
such as mites and aerosolized liquids, and larger
particles such as soot from wood fires or diesel fuel
ignition.
ü Air Toxics. The CAA identifies 188 substances as air
toxics or hazardous air pollutants, with lead being the
only one that is currently classified as a criteria
pollutant and thus regulated. Air toxic pollutants are
more acute biological hazards than most particulate or
criteria pollutants but are much smaller in volume.
Procedures are now underway to regulate other air
toxics under the CAA.
The greenhouse gases are water vapor, carbon dioxide,
methane, nitrous oxide, and a host of engineered chemicals,
such as chlorofluorocarbons (Figure 21). These gases
regulate the Earth’s temperature. When the natural balance
of the atmosphere is disturbed, particularly by an increase
or decrease in the greenhouse gases, the Earth’s climate
could be affected.
The combustion of fossil fuels produces 84 percent of U.S.
anthropogenic (created by humans) greenhouse emissions.3
When wood burning is included, these fuels produce
95 percent of the nitrogen oxides, 94 percent of the carbon
monoxide, and 93 percent of the sulfur dioxide criteria
pollutants (Figure 20). Most of these emissions are released
into the atmosphere as a result of fossil fuel use in
industrial boilers and power plants and in motor vehicles.
Emissions from Burning Natural Gas
Natural gas is less chemically complex than other fuels, has
fewer impurities, and its combustion accordingly results in
less pollution. Natural gas consists primarily of methane
(see box, p. 52). In the simplest case, complete combustive
reaction of a molecule of pure methane (which comprises
one carbon atom and four hydrogen atoms) with two
molecules of pure oxygen produces a molecule of carbon
dioxide gas, two molecules of water in vapor form, and
heat.4 In practice, however, the combustion process is never
1Energy Information Administration, Annual Energy Outlook 1999,
DOE/EIA-0383(99) (Washington, DC, December 1998). Energy Information Administration, Emissions of Greenhouse Gases in
2Note that methane, the principal ingredient in natural gas, is not classed the United States 1997, DOE/EIA-0573(97) (Washington, DC, October
as a volatile organic compound because it is not as chemically reactive as the 1998).
other hydrocarbons, although it is a greenhouse gas. As described by CH + 2 O 9 CO + 2 H O + heat.
3
4
4 2 2 2
(W e ig h te d b y
G re e n h o u s e
P o te n t ia l )
G re e n h o u s e
G a s e s
(C H )
8 3 .8 %
5 ,4 2 2 M i l l i o n
M e t r ic To n s
To ta l
N 2 O - 4 . 8 %
M e th a n e
C F C - 2 .1 %
9 .3 %
2 9 .1 M i l l i o n
M e t r ic To n s
To ta l
O th e r - 1 %
C o a l -3 5 %
O i l - 4 2 %
C o a l M in in g - 1 1 %
A n im a ls - 2 8 %
L a n d fi l l - 3 5 %
O th e r - 5 %
(C O 2 )
C a rb o n D io x id e
S o u rc e s o f
M e th a n e
4
S o u rc e s o f
C a rb o n D iox id e
G a s - 2 2 %
N a tu ra l G a s
P ro d u c t io n a n d
D is tr ib u t io n - 2 1 %
(M illion To ns)
Other - 7%
Par ticu la te M atter*
(PM10)
31.3
Vola tile O rganic
Compounds (VOC)
19.1
Oil - 16%
Coal - 7 4%
Carbon M onoxide
(CO)
88.8
Sulfur D ioxide
(SO )
19.1 2
Other - 6%
Wood - 13%
O il
(Engines and
Veh icles) - 81%
Wood - 8%
Solvents - 33%
Oil - 50%
Coal - 27%
Other - 5%
Lead** - 3 .9
O il
(Engines and
Ve h icles) -
58%
Pollutants
Nitrogen O xides
(NO )
23.4
X
Gas - 10%
Oth e r - 9%
Sources of
Vola tile O rganic
Compounds
Sources of
Carbon M onoxide
Sources of
Su lfu r D iox id e
Sources of
Nitrogen O xides
Gas - 3%
Energy Information Administration
Natural Gas 1998: Issues and Trends 51
Figure 20. U.S. Criteria Pollutants and Their Major Sources, 1996
*Wood and other fuels account for only 9 percent of particulate matter.
**Oil accounts for 25 percent of lead and other fuels 2 percent.
Source: Energy Information Administration, Office of Oil and Gas, derived from: Environmental Protection Agency, National Air Pollutant
Emission Trends 1990-1996, Appendix A (December 1997).
N2O = Nitrous oxide. CFC = Chlorofluorocarbon.
Source: Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997 (October 1998).
Figure 21. U.S. Anthropogenic Greenhouse Gases and Their Sources, 1997
Energy Information Administration
52 Natural Gas 1998: Issues and Trends
Sources and Chemical Composition of Natural Gas
Natural gas is obtained principally from conventional crude oil and nonassociated gas reservoirs, and secondarily
from coal beds, tight sandstones, and Devonian shales. Some is also produced from minor sources such as landfills.
In the future, it may also be obtained from natural gas hydrate deposits located beneath the sea floor in deep water
on the continental shelves or associated with thick subsurface permafrost zones in the Arctic.
Natural gas is a mixture of low molecular-weight aliphatic (straight chain) hydrocarbon compounds that are gases
at surface pressure and temperature conditions. At the pressure and temperature conditions of the source reservoir,
it may occur as free gas (bubbles) or be dissolved in either crude oil or brine. While the primary constituent of natural
gas is methane (CH ), it may contain smaller amounts of other hydrocarbons, such as ethane (C H ) and various 4 2 6
isomers of propane (C H ), butane (C H ), and the pentanes (C H ), as well as trace amounts of heavier 3 8 4 10 5 12
hydrocarbons. Nonhydrocarbon gases, such as carbon dioxide (CO ), helium (He), hydrogen sulfide (H S), nitrogen 2 2
(N ), and water vapor (H O), may also be present in any proportion to the total hydrocarbon content. 2 2
Pipeline-quality natural gas contains at least 80 percent methane and has a minimum heat content of 870 Btu per
standard cubic foot. Most pipeline natural gas significantly exceeds both minimum specifications. Since natural gas
has by far the lowest energy density of the common hydrocarbon fuels, by volume (not weight) much more of it must
be used to provide a given amount of energy. Natural gas is also much less physically dense, weighing about half
as much (55 percent) as the same volume of dry air at the same pressure. It is consequently buoyant in air, in which
it is also combustible at concentrations ranging from 5 percent to 15 percent by volume.
that perfect as it takes place in air rather than in pure gas. For example, all fossil fuels contain sulfur; its removal
oxygen, resulting in some pollutants.5 from both oil and gas is a major part of the processing of
The reaction products include particulate carbon, carbon removed during processing. When the fuel is burned,
monoxide, and nitrogen oxides, in addition to carbon several oxides of sulfur are produced, consisting primarily
dioxide, water vapor, and heat. Carbon monoxide, the of sulfur dioxide, some other sulfur-bearing acids, and
nitrogen oxides, and particulate carbon are criteria traces of many other sulfur compounds depending on what
pollutants (regulated emissions). The proportions of the other trace compounds are present in the fuel. Additionally,
reaction products are determined by the efficiency of since natural gas is both colorless and odorless, sulfurcombustion.
For instance, when the air supply to a gas bearing odorants are intentionally added to the gas stream
burner is not adequate, the produced levels of carbon by gas distributors so that residential consumers can smell
monoxide and other pollutants are greater. This situation is, a leak. Besides sulfur, natural gas can include other trace
of course, similar to that of all other fossil hydrocarbon impurities and contaminants.
fuels—insufficient oxygen supply to the burner will
inevitably result in incomplete combustion and the Yet the emittable pollutants resulting from combustion of
consequent production of carbon monoxide and other natural gas are far fewer in volume and number than those
pollutants. from the combustion of any other fossil fuel (Figure 22).
Since natural gas is never pure methane and air is not just combusted, and in part because natural gas has fewer
oxygen and nitrogen, small amounts of additional impurities than other hydrocarbon fuels. For example, the
pollutants are also generated during combustion of natural amount of sulfur in natural gas is much less than that of
these fuels prior to distribution. However, not all sulfur is
6
7
This occurs in part because natural gas is more easily fully
5Since the process takes place in air rather than pure oxygen, the practical xylene, and organometallic compounds such as methyl mercury. The list of
result is more like: CH + O + N 9 C + CO + CO + N O + NO + NO + combustion byproducts can include fine particulate matter, polycyclic 4 2 2 2 2 2
H O + CH (unburned) + heat (exact proportions depend on the prevailing aromatic hydrocarbons, and volatile organic compounds including 2 4
combustion conditions). formaldehyde.
6These odorants are compounds such as dimethyl sulfide, tertiary butyl
mercaptan, tetrahydrothiophene, and methyl mercaptan.
7Trace impurities can include radon, benzene, toluene, ethylbenzene,
0
50,000
100,000
150,000
200,000
250,000
of Energy Consumed
Pounds per Billion Btu
CO2
0
500
1,000
1,500
2,000
2,500
3,000
of Energy Consumed
Pounds per Billion Btu
NO x SO2 Particulates CO HC
CO HC
of Energy Consumed
Pounds per Billion Btu
0
50
250
200
150
100
Natural Gas Oil Coal
Energy Information Administration
Natural Gas 1998: Issues and Trends 53
Figure 22. Air Pollutant Emissions by Fuel Type
CO2 = Carbon dioxide. Nox = Nitrogen oxides. SO2 = Sulfur dioxide. CO = Carbon monoxide. HC = Hydrocarbon.
Note: Graphs should not be directly compared because vertical scales differ.
Source: Energy Information Administration (EIA) Office of Oil and Gas. Carbon Monoxide: derived from EIA, Emissions of Greenhouse Gases
in the United States 1997, Table B1, p. 106. Other Pollutants: derived from Environmental Protection Agency, Compilation of Air Pollutant Emission
Factors, Vol. 1 (1998). Based on conversion factors derived from EIA, Cost and Quality of Fuels for Electric Utility Plants (1996).
coal or oil. U.S. coals contain an average of 1.6 percent comprising about 1 ppm hydrogen sulfide and less than
sulfur by weight,8 and the oil burned at electric utility 2 ppm of each sulfur-bearing odorant.
power plants ranges from 0.5 percent to 1.4 percent sulfur.9
Diesel fuel has less than 0.05 percent sulfur by weight (or
500 parts per million (ppm)) and the current national
average for motor gasoline is 340 ppm sulfur (includes
California where the regulated statewide average is
30 ppm).10 Comparatively, natural gas at the burner tip has
less than 5 ppm of all sulfur compounds, typically
11
Toxic and Particulate Emissions
The combustion of natural gas also produces significantly
lower quantities of other undesirable compounds,
8U.S. coals burned at Clean Air Act Phase I electric power plants contain bearing odorants are 2.0 ppm. Institute for Gas Technology tests of trace
an average of 0.3 percent sulfur for western coals and 2.5 percent for eastern constituents in two intrastate pipeline samples and two Canadian interstate
coals, yielding a consumption-weighted national average of 1.6 percent sulfur samples supplied by the Pacific Gas and Electric Company had less than
by weight. 5 ppm total H S (usually between 1 and 1.5 ppm). Sulfur content by contract
9Energy Information Administration, Electric Power Annual, 1996, for pipeline-quality natural gas varies from 0.25 grains to 1.0 grain per
Vol. 2, DOE/EIA-348(96) (Washington, DC, 1997), p. 41. 100 standard cubic feet (1.9 ppm to 7.6 ppm), in many cases 0.25 grains or
10Gerald Karey, “EPA leaves sulfur verdict for another day,” Platts 1.9 ppm. Dr. John M. Campbell, Chapter 7, “Product Specifications,” Gas
Oilgram News, 76/78 (April 24, 1998), p. 4. Conditioning and Processing, Vol. 1 (Norman, OK, 1979).
11Washington Gas Light Company personnel stated that its system
hydrogen sulfide (H S) levels are 1.8 parts per million (ppm) and the sulfur- 2
2
Energy Information Administration
54 Natural Gas 1998: Issues and Trends
particularly toxics, than those produced from combustion larger, set in 1987. Although power plants and dieselof
petroleum products or coal. Toxic air pollutants are those powered trucks and buses are major emitters of particulate
compounds that are not specifically covered under other matter, the bulk of 10-micron-plus particulate matter
portions of the CAA (i.e., the criteria pollutants and emissions is composed of “fugitive” dust from roadways
particulate matter) and are typically carcinogens, (58 percent) and combined sources of agricultural
reproductive toxics, and mutagens. The United States emits operations and wind erosion (30 percent).
2.7 billion pounds of toxics into the atmosphere each year.
Motor vehicles are the primary source, followed by
residential wood combustion. Section 112 of the CAA of
1990 lists 188 toxic compounds or groups as hazardous air
pollutants (HAPs), including various compounds of
mercury, arsenic, lead, nickel, and beryllium and also
organic compounds, such as toluene, benzene,
formaldehyde, chloroform, and phosgene, which are
expected to be regulated soon. Presently, only lead is
regulated.
The toxic compound benzene can be a component of both
petroleum products and natural gas, but whereas it can
comprise up to 1.5 percent by weight of motor gasoline, the
levels in natural gas are considered insignificant and are not
generally monitored by gas-processing plants and most
pipeline companies.12 As required by California Proposition
65, the Safe Drinking Water and Toxic Enforcement Act,
gas pipeline companies that operate in California
continuously monitor for toxic substances. These
companies have found that the benzene and toluene content
of the natural gas they carry varies by source and can range
from less than 0.4 ppm to 6 ppm for interstate gas and up to
100 ppm for intrastate gas.13 Depending on the efficiency of
the combustion, some will be oxidized to carbon dioxide
and water, some will pass through unburned, and some will
be converted to other toxic compounds.
The particulates produced by natural gas combustion are
usually less than 1 micrometer (micron) in diameter and are
composed of low molecular-weight hydrocarbons that are
not fully combusted.14 Typically, combustion of the other
fossil fuels produces greater volumes of larger and more
complex particulates. In 1998, the Environmental
Protection Agency set a new standard for very fine (less
than 2.5 microns) particulates as an add-on to the existing
regulation of suspended particulates that are 10 microns or
15
16
Acid Rain and Smog Formation
Natural gas is not a significant contributor to acid rain
formation. Acid rain is formed when sulfur dioxide and the
nitrogen oxides chemically react with water vapor and
oxidants in the presence of sunlight to produce various
acidic compounds, such as sulfuric acid and nitric acid.
Electric utility plants generate about 70 percent of SO2
emissions and 30 percent of NO emissions in the United x
States; motor vehicles are the second largest source of both.
Natural gas is responsible for only 3 percent of sulfur
dioxide and 10 percent of nitrogen oxides (Figure 20).
Precipitation in the form of rain, snow, ice, and fog causes
about half of these atmospheric acids to fall to the ground
as “acid rain,” while about half fall as dry particles and
gases. Winds can blow the particles and compounds
hundreds of miles from their source before they are
deposited, and they and their sulfate and nitrate derivatives
contribute to atmospheric haze prior to eventual deposition
as acid rain. The dry particles that land on surfaces are also
washed off by rain, increasing the acidity of runoff.
Natural gas use also is not much of a factor in smog
formation. As opposed to petroleum products and coal, the
combustion of natural gas results in relatively small
production of smog-forming pollutants. The primary
constituent of smog is ground-level ozone created by
photochemical reactions in the near-surface atmosphere
involving a combination of pollutants from many sources,
including motor vehicle exhausts, volatile organic
compounds such as paints and solvents, and smokestack
emissions. The smog-forming pollutants literally cook in
the air as they mix together and are acted on by heat and
sunlight. The wind can blow smog-forming pollutants away
12Based on communications with personnel at the Gas Processors pollution, in Donora, Pennsylvania, and in London, England, during the
Association and the Columbia Gas Pipeline Company. 1930s-1950s, killed thousands of people, and recent studies have indicated
13Institute for Gas Technology test of trace constituents in two intrastate that a relatively small rise in 2.5-micron particulates causes a 5-percent rise
pipeline samples and two Canadian interstate samples supplied by the Pacific in infant mortality and greater risk of heart disease. Michael Day, “Taken to
Gas and Electric Company. Heart,” New Scientist (May 9, 1998), p. 23.
14The aerosolized particulate matter resulting from combustion of fossil Environmental Protection Agency, National Air Pollution Trends
fuels is a mixture of solid particles and liquid droplets inclusive of soot, Update, 1970-1997, EPA-454/E-98-007 (December 1998), Table A-5
smoke, dust, ash, and condensing vapors. “Particulate Matter (PM-10) Emissions.”
15The larger particles are usually trapped in the upper respiratory tract,
whereas those smaller than 10 microns can penetrate further into the
respiratory system. The most infamous cases of extreme particulate matter
16
Energy Information Administration
Natural Gas 1998: Issues and Trends 55
from their sources while the reaction takes place, explaining that of carbon dioxide, so although methane emissions
why smog can be more severe miles away from the source amount to only 0.5 percent of U.S. emissions of carbon
of pollutants than at the source itself. dioxide, they account for about 10 percent of the
Greenhouse Gases and Climate Change
The Earth’s surface temperature is maintained at a habitable
level through the action of certain atmospheric gases known
as “greenhouse gases” that help trap the Sun’s heat close to
the Earth’s surface. The main greenhouse gases are water
vapor, carbon dioxide, methane, nitrous oxide, and several
engineered chemicals, such as chlorofluorocarbons. Most
greenhouse gases occur naturally, but concentrations of
carbon dioxide and other greenhouse gases in the Earth’s
atmosphere have been increasing since the Industrial
Revolution with the increased combustion of fossil fuels
and increased agricultural operations. Of late there has been
concern that if this increase continues unabated, the
ultimate result could be that more heat would be trapped,
adversely affecting Earth’s climate. Consequently,
governments worldwide are attempting to find some
mechanisms for reducing emissions or increasing
absorption of greenhouse gases.17
On a carbon-equivalent basis, 99 percent of
anthropogenically-sourced carbon dioxide emissions in the
United States is due to the burning of fossil hydrocarbon
fuels, with 22 percent of this attributed to natural gas (Table
1). Carbon dioxide emissions accounted for 83.8 percent of
U.S. greenhouse gas emissions in 1997. Between 1996 and
1997, total estimated U.S. carbon dioxide emissions
increased by 1.5 percent (22.0 million metric tons) to about
1,501 million metric tons of carbon, representing an
increase of about 145 million metric tons, or almost 10.7
percent over the 1990 emission level. The increase between
1996 and 1997 was the sixth consecutive one. Increasing
reliance on coal for electricity generation is one of the
driving forces behind the growth in carbon emissions in
1996 and 1997.
The major constituent of natural gas, methane, also directly
contributes to the greenhouse effect. Its ability to trap heat
in the atmosphere is estimated to be 21 times greater than
greenhouse effect of U.S. emissions. In 1997, methane
emissions from waste management operations (primarily
landfills), at 10.4 million metric tons, and from agricultural
operations, at 8.6 million metric tons, substantially
exceeded those from the oil and gas industries combined,
estimated to be 6.2 million metric tons.18
Water vapor is the most common greenhouse gas, at about
1 percent of the atmosphere by weight, followed by carbon
dioxide at 0.04 percent and then methane, nitrous oxide,
and manmade compounds such as the chlorofluorocarbons
(CFCs). Each gas has a different residence time in the
atmosphere, from about a decade for carbon dioxide to
120 years for nitrous oxide and up to 50,000 years for some
of the CFCs. Water vapor is omnipresent and continually
cycles into and out of the atmosphere. In estimating the
effect of these greenhouse gases on climate, both the global
warming potential (heat-trapping effectiveness relative to
carbon dioxide) and the quantity of gas must be considered
for each of the greenhouse gases.
Since human activity has minimal impact on the
atmosphere’s water vapor content, unlike the other
greenhouse gases it is not addressed in the context of global
warming prevention. The criteria pollutants specified in the
CAA are reactive gases that, although they decay quickly,
nevertheless promote reactions in the atmosphere yielding
the greenhouse gas ozone. These gases indirectly affect
global climate because they produce undesirable lower
atmosphere ozone, as opposed to the desirable high-altitude
ozone that shields Earth from most of the Sun’s ultraviolet
radiation. Carbon dioxide, on the other hand, directly
contributes to the greenhouse effect; it presently represents
61 percent of the worldwide global warming potential of
the atmosphere’s greenhouse gases.
The United States is the largest producer of carbon dioxide
among the countries of the world, both per capita (5.4 tons
in 1996) and absolutely (Figure 23).19 The amount of
carbon dioxide produced for an equivalent amount of heat
production substantially varies among the fossil fuels, with
17In December 1997, representatives from more than 160 countries met 1998), pp. 27 and 29.
in Kyoto, Japan, to establish limits on greenhouse gas emissions for U.S. Department of Energy, Oak Ridge National Laboratory, G.
participating developed nations. The resulting Kyoto Protocol established Marland and T. Broden, “Ranking of the World’s Countries by 1995 Total
annual emission targets for countries relative to their 1990 emission levels. CO Emissions from Fossil Fuel Burning, Cement Production, and Gas
The target for the United States is 7 percent below 1990 levels. Flaring,”<http://cdiac.esd.ornl.gov/trends/emis/top95.tot>.
18Energy Information Administration, Emissions of Greenhouse Gases in
the United States 1997, DOE/EIA-0573(97) (Washington, DC, October
19
2
China
Russian Federation
Japan
India
Germany
United Kingdom
Ukraine Canada
Total 1995 emissions = 6,173 million metric tons of carbon
United States
14.1%
8.0%
5.0%
4.0%
3.7%
2.4%
1.9% 1.9%
36.1%
22.8%
Rest of World
Energy Information Administration
56 Natural Gas 1998: Issues and Trends
Note: Sum of percentages does not equal 100 because of independent rounding.
Source: U.S. Department of Energy, Oak Ridge National Laboratory, G. Marland, T. Broden, “Ranking of the World’s Countries by 1995 Total
CO2 Emissions from Fossil Fuel Burning, Cement Production, and Gas Flaring,” <http://cdiac.esd.ornl.gov/trends/emis/top95.tot>.
Figure 23. Carbon Dioxide Emission Share by Country, 1995
Table 1. U.S. Carbon Dioxide Emissions from Energy and Industry, 1990-1997
(Million Metric Tons of Carbon)
Fuel Type or Process 1990 1991 1992 1993 1994 1995 1996 P1997
Natural Gas
Consumption . . . . . . . . . . . . . . . . . . . . . . . . . . . . 273.2 278.1 286.3 296.6 301.5 319.1 319.7 319.1
Gas Flaring . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 2.8 2.8 3.7 3.8 4.7 4.5 4.3
CO2 in Natural Gas . . . . . . . . . . . . . . . . . . . . . . . 3.6 3.7 3.9 4.1 4.3 4.2 4.5 4.6
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 279.3 284.6 293.0 304.4 309.6 323.0 328.1 328.0
Other Energy
Petroleum . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 591.4 576.9 587.6 588.8 601.3 597.4 620.6 627.5
Coal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 481.5 475.7 478.1 494.4 495.6 500.2 520.9 533.0
Geothermal . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 0.1 0.1 0.1 0.1 * * * *
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,073.0 1,052.7 1,065.8 1,083.3 1,096.9 1,097.6 1,141.5 1,160.5
Other Sources
Cement Production . . . . . . . . . . . . . . . . . . . . . . . 8.9 8.7 8.8 9.3 9.8 9.9 9.9 10.1
Other Industrial . . . . . . . . . . . . . . . . . . . . . . . . . . 8.0 8.0 8.0 8.0 8.1 8.9 9.1 9.2
Adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . a -13.2 -13.2 -14.9 -11.3 -10.7 -11.2 -9.8 -7.1
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 3.5 1.9 6.0 7.2 7.6 9.2 12.2
Total from Energy and Industry . . . . . . . . . . . . 1,355.9 1,340.8 1,360.6 1,393.6 1,413.8 1,428.1 1,478.8 1,500.8
Percent Natural Gas of Total . . . . . . . . . . . . . . . 20.6 21.2 21.5 21.8 21.9 22.6 22.2 21.9
aAccounts for different methodologies in calculating emissions for U.S. territories.
*Less than 0.05 million metric tons.
P = Preliminary data.
Notes: Emission coefficients are annualized for coal, motor gasoline, liquefied petroleum gases, jet fuel, and crude oil. Includes emissions from
bunker fuels. Totals may not equal sum of components because of independent rounding.
Source: Energy Information Administration, Emissions of Greenhouse Gases in the United States 1997 (October 1998).
Energy Information Administration
Natural Gas 1998: Issues and Trends 57
natural gas producing the least. For the major fossil fuels, generators would have a sizable impact on emission levels.
the amounts of carbon dioxide produced for each billion However, if increased natural gas generation were to
Btu of heat energy extracted are: 208,000 pounds for coal, replace nuclear power or delay the commercialization of
164,000 pounds for petroleum products, and 117,000 renewable-powered generation, this would represent a
pounds for natural gas (Table 2). negative impact on emission levels.
Effect of Greater Use of
Natural Gas
Electric Power Generation
Projections of increased use of natural gas center
principally on the increased use of natural gas in electric
generation. For example, the Annual Energy Outlook 1999
reference case projects natural gas consumption to rise by
10.3 trillion cubic feet (Tcf) from 1997 to 2020. Of this
increase, 56 percent (5.8 Tcf) is expected to come as a
result of increased use of natural gas for electricity
generation. A recent Energy Information Administration
(EIA) Service Report (prepared at the request of the House
of Representatives Science Committee assuming no
changes in domestic policy) analyzed the consequences of
U.S. implementation of the Kyoto Protocol. In the carbon
reduction cases cited in this report, Impacts of the Kyoto
Protocol on U.S. Energy Markets and Economic Activity,20
power plant use of natural gas (excluding industrial
cogeneration) could increase to between 8 and 12 Tcf in
2010 and 12 to 15 Tcf in 2020. This growth is expected to
develop as many of the new generating units brought on
line are gas-fired. Some repowering of existing units may
be undertaken as well.
Since electricity generation is the major source of U.S.
sulfur dioxide (SO ) and carbon dioxide (CO ) emissions, 2 2
21
as well as a major source of all other air pollutants
excepting the chlorinated fluorocarbons, substitution of
natural gas for other fossil fuels by utilities and nonutility
In 1997, there were 10,454 electric utility generating units
in the United States, with a total net summer generation
capacity of 712 gigawatts. Of 22 that capacity, 19 percent
listed natural gas as the primary fuel and 27 percent listed
it as either the primary or secondary fuel. But natural gas
was actually used to generate only 9.1 percent of the
electricity generated by electric utilities in 1997, down
1.2 percent from the 1995 value of 10.3 percent and one of
the lowest proportions in the past 10 years. Coal was listed
as the primary fuel source for almost 43 percent of the
utility generating capacity and as a secondary source for
only about 0.5 percent. But in 1997, it was the fuel used for
57.3 percent of net generation from electric utilities, up
from 55.3 percent in 1995 and 56.3 percent in 1996.
A utility typically has a base-load generating capacity that
is essentially continuously on line and capable of satisfying
most or all of the minimum service-area load. The base-load
capacity is supplemented by intermediate-load generation
and peak-load generation capacities, which are used to meet
the seasonal and short-term fluctuating demands above base
load; reserve or standby units are also maintained to handle
outages or emergencies. The majority of non-nuclear baseload
units are coal-fired, yet many utilities have gas
turbines, which are primarily used as peak-load generators.
Once the initial cost of a generating unit is paid for, fuel
cost per unit of energy produced controls how electricity is
generated. In 1997, the cost at steam-electric utility plants
per million Btu for coal was less than half that for natural
gas, $1.27 versus $2.76, and petroleum was even higher at
$2.88.23 The per Btu natural gas cost to utilities increased
by over one-third from 1995 to 1997, while the per Btu coal
cost continued a 15-year decline, contributing to the
decreased market share for natural gas. However, new
20Energy Information Administration, Impacts of the Kyoto Protocol on technologies creating higher efficiency natural gas electric
U.S. Energy Markets and Economic Activity, SR/OIAF/98-03 (Washington,
DC, October 1998), p. 76. This Service Report was requested by the U.S.
House of Representatives Science Committee to provide information on the
costs of the Kyoto Protocol without other changes in laws and regulations.
The report relied on assumptions provided by the Committee.
21In 1996, electric utilities accounted for 12,604 thousand short tons of
sulfur dioxide emissions out of a total of 19,113 thousand short tons Excludes nonutility generators. Energy Information Administration,
(Environmental Protection Agency, National Air Pollutant Emission Trends, Inventory of Power Plants in the United States as of January 1, 1998,
1990-1996, EPA-454R-97-011 (December 1997), Table 2-1, p. 2-4); and for DOE/EIA-0095(98) (Washington, DC, December 1998). Nonutility
532.4 million metric tons of carbon as carbon dioxide, exceeding the generators totaled 78 gigawatts of capacity in 1997, with 42 percent utilizing
482.9 and 473.1 million metric tons from the industrial and transportation natural gas. Energy Information Administration, Electric Power Annual 1997,
sectors, respectively (Energy Information Administration, Emissions of Vol. II, DOE/EIA-348(97) (Washington, DC, July 1998), Table 54.
Greenhouse Gases in the United States 1997, DOE/EIA-0573(97) (October Energy Information Administration, Electric Power Annual 1997,
1998), Table 7, p. 21). Vol. 1, DOE/EIA-348(97) (Washington DC, July 1998), Table 20, p. 37.
22
23
Energy Information Administration
58 Natural Gas 1998: Issues and Trends
Table 2. Pounds of Air Pollutants Produced per Billion Btu of Energy
Pollutant Natural Gas Oil Coal
Carbon Dioxide 117,000 164,000 208,000
Carbon Monoxide 40 33 208
Nitrogen Oxides 92 448 457
Sulfur Dioxide 0.6 1,122 2,591
Particulates 7.0 84 2,744
Formaldehyde 0.750 0.220 0.221
Mercury 0.000 0.007 0.016
Notes: No post combustion removal of pollutants. Bituminous coal burned in a spreader stoker is compared with No. 6 fuel oil burned in an oil-fired
utility boiler and natural gas burned in uncontrolled residential gas burners. Conversion factors are: bituminous coal at 12,027 Btu per pound and 1.64
percent sulfur content; and No. 6 fuel oil at 6.287 million Btu per barrel and 1.03 percent sulfur content—derived from Energy Information
Administration, Cost and Quality of Fuels for Electric Utility Plants (1996).
Source: Energy Information Administration (EIA), Office of Oil and Gas. Carbon Monoxide: derived from EIA, Emissions of Greenhouse Gases
in the United States 1997, Table B1, p. 106. Other Pollutants: derived from Environmental Protection Agency, Compilation of Air Pollutant Emission
Factors, Vol. 1 (1998).
generators can overcome the current price differential turbine repowering where a new gas turbine and a heat
between the fuels. recovery steam generator are integrated with the existing
The new power plants scheduled to come on line during the have lower capital costs if site redesign costs are low, but
10 years from 1998 through 2007 are 88 percent natural- entails a higher operating cost because it is less efficient
gas-fired and only 5 percent coal-fired, but they will add than total state-of-the-art repowering.
only about 6 percent to total net generation capacity.24
Thus, in order to make significant reductions in the volume As of January 1, 1998, there are 20 repowering projects
of greenhouse gases and other pollutants produced by planned in nine States that will primarily convert current
electricity generation, a significant amount of new oil-fired facilities to natural gas or co-firing capability; most
unplanned gas-fired or renewable generation capacity of the projects are driven by economics with a secondary
would have to be built, or the existing generating impetus as a response to the emission reduction
equipment having natural gas as a fuel option would have requirements of the Clean Air Act Amendments of 1990
to be utilized more and many of the existing coal plants (see box, p. 59).
would have to be repowered to burn gas.
The utilities have many supply-side options at their number of plants without expansion of the transportation
disposal to reduce or offset carbon dioxide emissions from pipeline network. Most of the candidate plants are located
power generation. These options include repowering of in primary gas-consuming regions served by major trunk
coal-based plants with natural gas, building new gas plants, lines. It appears that converted plants may have sufficient
extension of the life of existing nuclear plants, access to firm transportation capacity on these systems
implementation of renewable electricity technologies, and during the heating and nonheating seasons, during which
improvement of the efficiency of existing generation, between 16 and 24 percent of average national system
transmission, and distribution systems. capability is available for firm transportation, respectively.
There are two principal conversion opportunities for utility gas supply will depend on the location and specific load
power plants. The simplest and most capital-intensive characteristics of the pipelines serving that plant. However,
approach is site repowering with an entirely new gas- because of recent regulatory reforms, electric generation
turbine-based natural gas combined-cycle (NGCC) system. plants may no longer be required to use firm
The more complex, less capital-intensive approach is steam transportation to serve their supply needs. Under Federal
steam turbine and auxiliary equipment. This option can
Complete conversion may not be a practical goal for a
25
The ability of a plant to use firm transportation capacity for
24Energy Information Administration, Inventory of Power Plants in the Energy Information Administration, Deliverability on the Interstate
United States as of January 1, 1998, DOE/EIA-0095(98) (Washington, DC, Natural Gas Pipeline System, DOE/EIA-0618(98) (Washington, DC, May
December 1998), pp. 9 and 13. 1998), Table 14.
25
Energy Information Administration
Natural Gas 1998: Issues and Trends 59
Clean Air Act Amendments of 1990: Emission Reduction Requirements for Utilities
The 1990 amendments to the Clean Air Act (CAA) require that electric utilities reduce their sulfur dioxide (SO ) 2
emissions by 10 million tons from the 1980 levels to attain an absolute cap of 8.9 million tons of SO by 2000. 2
Comparatively, SO emissions from fossil-fueled electric generating units ranged from 15.0 million tons in 1993 to 2
11.6 million tons in 1995, with 12.2 million tons emitted in 1996. The same units also emitted 2,047.4 million tons
of carbon dioxide (CO ) in 1996, up from 1,967.7 million tons in 1995. Nonutility power producers added another 2
1.2 million tons of SO and 556 million tons of CO in 1995, the latest year for which data are available. Phase 1 of 2 2
the CAA, 1995 through 1999, requires the largest polluters (110 named power plants) to reduce emissions beginning
in 1995. The top 50 polluting plants produced 5,381 million tons of SO emissions in 1996, 44 percent of the electric 2
generation total. The second phase, effective January 1, 2000, will require approximately 2,000 plants to reduce
their emissions to half the level of Phase I. The affected plants are required to install systems that continuously
monitor emissions in order to track progress and assure compliance, and are allowed to trade emission allowances
within their systems and with the other affected sources. Each source must have sufficient allowances to cover its
annual emissions. If not, the source is subject to a $2,000 per ton excess emissions fee and a requirement to offset
the excess emissions in the following year. Bonus allowances can be earned for several reasons including early
reductions in emissions and re-powering with a qualifying clean coal technology.
The CAA also requires the utilities to reduce their nitrogen oxide (NO ) emissions by 2 million tons from the 1980 x
levels. In September 1998, the Environmental Protection Agency issued a new source performance standard for
NO emissions from new (post-July 1997) electric utility and industrial/commercial/institutional steam generating x
units, including those that may become subject to such regulation via modification or reconstruction. The
performance standard for new electric utility steam-generating units is 1.6 pounds per megawatthour of gross energy
output regardless of fuel type, whereas that for modified/reconstructed units is 0.15 pounds per million Btu (MMBtu)
of heat input. The standard for new industrial/commercial institutional steam generating units is 0.2 pounds per
MMBtu of heat input, although for low heat-rate units firing natural gas or distillate oil the present limit of 0.1 pounds
per MMBtu is retained. The switch from input-based to output-based accounting favors increased generating
efficiency and the use of natural gas over distillate oil and especially coal, without the need to prescribe specific
pollution control options.
electric restructuring, power plants may be able to use gasoline- and diesel-powered motor vehicles. As the U.S.
significantly more interruptible capacity or be able to use automobile industry first developed, experimentation with
released capacity to satisfy their supply needs. compressed natural gas (CNG) and other alternative fuels
Nonutility generation (NUG) of electric power is a increasingly plentiful, accessible, and inexpensive, these
relatively recent and rapidly growing industry. The share of alternatives were largely pushed aside and U.S.
total electricity generated by NUGs has increased from 6.2 transportation systems became petroleum-based. While few
percent in 1989 to 11.5 percent in 1997. Nonutilities are Americans have driven or 26 owned a natural-gas-powered
generally smaller than utilities and were encouraged by the vehicle (NGV), people in other nations have been driving
passage of the Public Utility Regulatory Policies Act in them since World War II when severe petroleum
1978. Natural gas is the primary fossil fuel used in these shortages curtailed gasoline availability. About 1,000,000
applications, accounting for over 72 percent in 1997. NGVs are presently in use worldwide, with Italy alone
Transportation Sector
The second largest source of air pollution in the United
States is the transportation sector, and in particular
was conducted. But as petroleum products became
having more than 400,000 on the road. In contrast, fewer
than 75,000 NGVs can be found on U.S. roads, not quite
0.04 percent of the more than 200 million U.S. vehicles.
NGVs had a minuscule share of the U.S. vehicle fuel
market in 1997, less than 1 billion cubic feet in a market
equivalent to 30 trillion cubic feet.
26Energy Information Administration, Monthly Energy Review, DOE/EIA-
0035(99/02) (Washington, DC, February 1999).
Energy Information Administration
60 Natural Gas 1998: Issues and Trends
Table 3. Forecasts of Natural Gas Consumption as a Vehicle Fuel
In 2000 In 2010
Source
Consumption
(billion cubic feet)
Number of Vehicles
(thousands)
Consumption
(billion cubic feet)
Number of Vehicles
(thousands)
Energy information Administration (EIA) 125 80 250 1,280
American Gas Association (AGA) 210 110 355 1,660
Gas Research Institute (GRI) 280 140 440 2,300
Sources: Energy Information Administration: Annual Energy Outlook 1999, Base Case Scenario (December 1998). AGA: American Gas
Association, 1998 AGA-TERA Base Case (July 1998). GRI: Draft of GRI04 Baseline Projections (November 1998).
Interest in clean-burning alternative fuels has increased in vehicles by model year 1998. In 1995 these urban areas,
recent years. After two oil embargoes, several oil price inclusive of their suburbs, were home to more than
spikes, and the 1991 Gulf War, both petroleum prices and 85 million Americans (almost one-third of the U.S.
security of supply remain major concerns. The population). They also have more than 30 percent of all
environmental problems associated with tailpipe emissions registered vehicles.
have also become a prime motivating factor. The
Environmental Protection Agency estimated that motor Most observers agree that the primary competition in the
vehicle tailpipe emissions are the source of more than half evolving alternative fuels market is among three alternative
of all urban air pollution in the United States. These issues, carbon-based fuels (methanol, ethanol, and compressed
along with the failure of many large U.S. metropolitan areas natural gas (CNG)), electric vehicle technology, and
to meet the 1987 deadline for achievement of the National reformulated gasoline (RFG). While liquefied petroleum
Ambient Air Quality Standards (primarily for ozone and gas (LPG or “propane”) has essentially the same qualities
carbon monoxide), have led to increased interest in as CNG with respect to emissions, range, safety, and
alternative transportation fuels. There are a number of fuel cost, and is widely used in U.S. rural agricultural areas,
alternatives to gasoline, among which are electricity, its supply probably could not meet broad expansion of
methanol (produced from natural gas and butane), ethanol demand. Less than 50 percent of LPG production is derived
(produced from agricultural products), propane, liquefied from natural gas; the majority of it is a byproduct of the oil
natural gas, and compressed natural gas. In the future, these refining process. Therefore, any significantly expanded use
alternatives will compete with each other and with the of LPG would require increased oil imports.
“cleaner” reformulations of gasoline now being tested and
other more flexible new technologies, such as hybrid Widespread use of CNG as a transportation fuel would
gasoline-electric or diesel-electric vehicles. The relative entail substantial new investment to expand the natural gas
success of these alternatives depends on numerous factors: delivery infrastructure, largely involving massive addition
automobile performance, ability to adapt the fuel of refueling stations at a cost of at least $165,000 each. The
distribution and marketing system, environmental impacts, CNG vehicles presently used in the United States, mostly
safety, the economics of both fuel and vehicle, changes in fleet vehicles, are supported by fewer than 1,300 refueling
technology, and public awareness and acceptance. stations as compared with more than 200,000 refueling
A number of legislative measures and regulatory initiatives Fewer than 700 of the latter offer CNG to the general
have sought to ameliorate the automotive emissions public, and then often by appointment only. EIA and other
problem. The Clean Air Act Amendments of 1990 mandate forecasters project limited growth in the use of CNG as an
that in the 22 cities with 1988 populations of greater than automotive fuel with most projections for 2010
250,000, where ozone and/or carbon monoxide levels are consumption falling in the range of 250 to 440 billion cubic
most serious (nonattainment areas), owners of fleets of feet and less than 2.5 million vehicles (Table 3). It is quite
10 or more vehicles must begin purchasing clean-burning likely that future NGV use will remain restricted to fleet
stations serving gasoline and diesel powered vehicles.
vehicles.
Energy Information Administration
Natural Gas 1998: Issues and Trends 61
Air Conditioning Market
The primary opportunity for air pollution reduction in the
space-conditioning market is use of natural gas in lieu of
electricity for cooling. This would include gas-fired air
conditioning for commercial, institutional, and industrial
buildings and gas-fired heat pumps for residential and small
commercial applications. In space-conditioning
applications, natural gas competes with electricity and with
energy conservation alternatives. Electricity currently
dominates commercial and industrial cooling with a market
share of more than 90 percent, while gas cooling’s share is
in the 3 to 7 percent range; consumption of gas for space
cooling in 1997 was less than 100 billion cubic feet. This
was not always the case. From the mid-1950s through the
early 1970s, the gas cooling (often called gas absorption)
equipment share of the large-tonnage cooling market
ranged between 20 and 30 percent, with annual load
additions ranging from 2 to over 4 billion cubic feet
supplying 200 to 300 thousand tons of cooling. The load
declined precipitously in the mid-1970s because of energy
supply/price dislocations, regulatory restrictions on gas
industry marketing, and consequent reductions in support
activities by many manufacturers; shipments of largetonnage
absorption equipment declined to less than
50 thousand tons per year.
Gas absorption technology and market development
continued in Japan, where gas serves more than half of the
large-tonnage cooling market. The absorption share of
chiller unit shipments in Japan continues to increase; in
1991 it accounted for over 90 percent of new units. Several
Japanese companies have become major worldwide
suppliers of absorption equipment, and gas-cooling
research and development (R&D) expenditures by the
Japanese government and manufacturers continue to grow.
In the United States, R&D conducted by the natural gas
industry, the Gas Research Institute, and gas equipment
manufacturers has led to commercialization of a variety of
new gas engine-drive, absorption, and desiccant
technologies. In addition, equipment and technologies from
the major Japanese companies are being imported or
licensed by U.S. firms. Over the past 2 to 3 years, all of the
major U.S. chiller manufacturers have substantially
increased their activity in gas cooling.
Despite the increased interest in using natural gas for space
cooling, electric cooling equipment is strongly established
(with more than 90 percent of the market) and well
supported by substantial R&D funding and strong
marketing. However, with the Federal government phasing
out the use of chlorofluorocarbons (CFCs or chlorine-based
refrigerants) used in electric cooling systems, natural gas
absorption systems, which operate free of CFCs, and
engine-driven and other natural-gas-based systems, which
typically operate on non-CFC refrigerants, should gain
some additional advantage.27
Environmental Impacts of Gas
Production and Delivery
The extraction and production of natural gas, as well as
other natural gas operations, do have environmental
consequences (Figure 24) and are subject to numerous
Federal and State laws and regulations (see box, p. 63). In
some areas, development is completely prohibited so as to
protect natural habitats and wetlands. At present, oil and
gas drilling is prohibited along the entire U.S. East Coast,
the west coast of Florida, and the U.S. West Coast except
for the area off the coast of southern California. Drilling is
also generally prohibited in national parks, monuments, and
designated wilderness areas.
Natural Gas Exploration and Production
The environmental side-effects of natural gas production
start in what is called the upstream portion of the natural
gas industry, beginning with selection of a geologically
promising area for possible future natural gas production.
An upstream firm will collect all available existing
information on the geology and natural gas potential of the
proposed area and may decide to conduct new geologic and
geophysical studies. It will usually need to acquire
permission to enter the area by obtaining permits for
Federal, State, or local government land or by leasing right
of access on private lands. If the road network is dense
enough, some area studies may only require access along
public right-of-way.
The most common new study is a seismic survey. Onshore
seismic surveys are done using either a small explosive
charge as the acoustic source or special vibrator trucks that
literally shake the ground. In water, the source is either a
small explosive charge or an air or gas gun. The primary
environmental disturbances involved with land operations
are the laying of cable and geophones. Sometimes this
27American Gas Association, Gas Industry Online: Gas Technology
Summer ‘97, “New Directions in Natural Gas Cooling,” <http://www.aga.
com/events/gtsu97/directions.html>.
Natural Gas and
Associated (Oil) Wells
Land Reclamation
Leakage from Unplugged Wells
Abandonment
Wetland and Wildlife Disturbance
Drilling Waste Disposal
Emissions from Drilling Activities
Potential Groundwater and Soil
Damage
Exploration and Development
Unprocessed
Waste Water Disposal
Potential Groundwater Intrusion
Emissions: Equipment, Separation
Activities, Unplugged Wells, Venting
and Flaring
Production
Local Distribution Companies
Losses of Odorant
Losses During Pressure Reduction
Line Loss Emissions
End-Use Consumption
Emissions From Combustion
Contaminant Disposal
Emissions: Separation Activities and
Equipment Leaks
Potential Groundwater Damage
Natural Gas Processing
LNG Only
Emissions from Refrigeration and
Vaporization
Natural Gas Storage
Site Development
Potential Groundwater and Soil Damage
Brine and WasteDisposal
Operations
Compressor Unit Noise and Emissions
Emissions from Injection/Withdrawals
Possible Water Table Intrusion
Dry Gas (Mainline) Transmission
Possible Wetlands, Wildlife, and Archaelogical Site
Disturbances
Valve Leak Emissions
Compressor Noise and Fuel Use Emissions
Possible PCB Contamination
Land Use Concerns
Erosion
Gas Distribution
Industrial
Sale
Residential Commercial Vehicle Fuel Electric Utility
Energy Information Administration
62 Natural Gas 1998: Issues and Trends
Figure 24. Environmental Impacts of Natural Gas Production, Transmission, and Distribution
LNG = Liquefied natural gas. PCB = Polychlorinated biphenyl.
Source: Energy Information Administration, Office of Oil and Gas.
Energy Information Administration
Natural Gas 1998: Issues and Trends 63
Environmental Laws Affecting Natural Gas Operations
Date Legislation Effect on Natural Gas Operations
1966 National Historic Preservation Act Major construction projects must avoid damaging or destroying designated National
Historic Landmarks.
1969 National Environmental Policy Act Requires a detailed environmental review before any major or controversial Federal
action, such as approval of an interstate pipeline or interstate gas storage facility.
1970 Amended
1977 and 1990
Clean Air Act Regulates air emissions from area, stationary, and mobile sources. Affects operations
of gas plants and is expected to cover glycol dehydrator operations.
1970 Occupational Safety and Health
Act
Governs worker exposure to toxic chemicals, excessive noise levels, mechanical
dangers, heat or cold stress, or unsanitary conditions.
1973 Endangered Species Act Nesting areas of endangered species must not be disturbed by construction or
operations. Drilling mud pits if used may have to be screened to prevent endangered
species from landing in them by mistake. Pipelines and gas storage sites should avoid
endangered species areas.
1974 Amended
1986
Safe Drinking Water Act Regulates underground injection wells and directs the protection of sole source
aquifers.
1976 Toxic Substance Control Act Gives the Environmental Protection Agency authority to require testing of chemical
substances, both new and old, and to regulate them where necessary. Limits or
prohibits the use of certain substances.
1976 Amended
1984
Resource Conservation and
Recovery Act
Encourages the conservation of natural resources through resource recovery. Defines
hazardous waste as waste which may cause an increase in mortality or poses a
substantial hazard to human health or the environment when improperly disposed. A
waste is: (a) hazardous if it is ignitable at less than 140 degrees F; (b) reactive if it
reacts violently with water, is normally unstable, generates toxic gases when exposed
to water or corrosive materials or is capable of detonation when exposed to heat or
flame; and, (c) corrosive if it has a pH & to 2 or ' to 12.5 and toxic if it meets or
exceeds a certain concentration of pesticides/herbicides, heavy metals or organics.
1977 Clean Water Act Regulates discharges of pollutants to U.S. waters. Wetlands are protected under this
act. Permits are required, conditioned to force either avoidance or mitigation banking.
Affects construction of pipelines and facilities in wetlands and dredging for drilling barge
movement in coastal wetlands. Provides for delegation of many permitting,
enforcement, and administrative aspects of the law to the States.
1980 Amended
1986
Comprehensive Environmental
Response, Compensation, and
Liability Act. Superfund Amendments
and Reauthorization Act.
Acts on hazardous waste activities that occurred in the past. Material does not have to
be a “waste.” Covers all environmental media: air, surface water, ground water and soil.
1982 Federal Oil and Gas Royalty
Management Act
Among other requirements, oil and gas facilities must be built in a way that protects the
environment and conserves Federal resources.
1986 Emergency Planning and
Community Right-to-Know Act
Facilities (gas plants and compressor stations) must report on the hazardous chemicals
they use and store, providing information on a chemical’s physical properties and health
effects, and a listing of chemicals that are present in excess of certain amounts.
1990 Oil Pollution Act Offshore drilling requires posting of significant pollution bonds.
1990 Pollution Prevention Act Prevents pollution through reduction or recycling of source material. Requires facility
owners or operators to include toxic chemical source reduction and recycling report for
any toxic chemical.
1992 Energy Policy Act Encourages development of clean-fuel vehicles; encourages energy conservation and
integrated resource planning.
Energy Information Administration
64 Natural Gas 1998: Issues and Trends
requires the cutting of roads or trails and, when explosives groundwater and on-site disposal is often not permitted, so
are used, the drilling of a small, short hole to encase them. operators must dispose of such wastes at an off-site
Explosives are rarely used in water anymore since they can disposal facility. The disposal methods used by commercial
stun or kill marine life in the immediate vicinity; the now disposal companies include underground injection, burial
commonly used gas or air gun source was developed to in pits or landfills, land spreading, evaporation,
ameliorate these effects, as well as increase personnel incineration, and reuse/recycling. In areas with subsurface
safety. salt formations, such as Texas, Louisiana, and New
Following analysis of the geologic and geophysical data, cost-competitive option. Such disposal poses very low risks
the firm may proceed to acquire the right to drill and to plant and animal life because the formations where the
produce natural gas from owners of the land and relevant caverns are constructed are very stable and are located
government permitting authorities. In making leasing and beneath any subsurface fresh water supplies. Water-based
permitting decisions involving Federal lands, the potential drilling wastes have been shown to have minimal impacts
environmental impacts of future development are often on aquatic life, so offshore operators are allowed to
considered. Such considerations include the projected discharge them into the sea. They are prohibited from so
numbers and extent of wells and related facilities, such as discharging oil-based drilling wastes, and these are
pipelines, compressor stations, water disposal facilities, as generally hauled to shore for disposal.
well as roads and power lines.
Disposal of Drilling Waste
The drilling of a gas well involves preparing the well site
by constructing a road to it if necessary, clearing the site,
and flooring it with wood or gravel. The soil under the road
and the site may be so compacted by the heavy equipment
used in drilling as to require compaction relief for
subsequent farming. In wetland areas, such as coastal
Louisiana, drilling is often done using a barge-mounted rig
that is floated to the site after a temporary slot is cut
through the levee bordering the nearest navigable stream.
However, the primary environmental concern directly
associated with drilling is not the surface site but the
disposal of drilling waste (spent drilling muds and rock Exploration, development, and production activities emit
cuttings, etc.). Early industry practice was to dump spent small volumes of air pollutants, mostly from the engines
drilling fluid and rock cuttings into pits dug alongside the used to power drilling rigs and various support and
well and just plow them over after drilling was completed, construction vehicles. An indication of the level of air
or dump them directly into the ocean if offshore. Today, emissions from these operations is available from wells in
however, the authority issuing the drilling permits, in the Federal Offshore off California (Table 4). As the
coordination with the EPA, determines whether the operator number of wells increases, such as in the Gulf of Mexico,
may discharge drilling fluids and solids to the environment so do the emissions for exploratory drilling and
or whether they must be shipped to a special disposal development drilling, while emissions from supporting
facility. Drilling of a typical gas well (6,000 feet deep) activities rise less directly. Offshore development entails
results in the production of about 150,000 pounds of rock some activities not found elsewhere (i.e., platform
cuttings and at least 470 barrels of spent mud.28 construction and marine support vessels), but the
At onshore and coastal sites, drilling wastes usually cannot include drilling pad and access road construction,
be discharged to surface waters and are primarily disposed especially for development drilling, are many times larger
of by operators on their lease sites. If the drilling fluids are because of the much higher level of activity.
saltwater- or oil-based, they can cause damage to soils and
Mexico, disposal in man-made salt caverns is an emerging,
In recent years, new drilling technologies such as slimhole
drilling, horizontal drilling, multilateral drilling, coiled
tubing drilling, and improved drill bits, have helped to
reduce the generated quantity of drilling wastes. Another
advanced drilling technology that provides pollutionprevention
benefits is the use of synthetic drilling fluids
which combine the superior drilling performance of oilbased
fluids with the more favorable environmental impacts
of water-based drilling fluids. Their use results in a much
cleaner well bore and less sidewall collapse, such that the
cuttings volume is reduced.
Emissions
environmental effects from onshore activities, which
28Assumes a 20-inch diameter hole to 200 feet followed by an 8-inch
(average) hole diameter for the next 5,800 feet, plus a mud pit volume of
35 barrels.
Energy Information Administration
Natural Gas 1998: Issues and Trends 65
Table 4. Typical Annual Air Pollutant Emissions from Exploration, Development, and Production Activities
Offshore California
Type of Air Pollutant Emission
(short tons per year)
Activity Compounds Nitrogen Oxides Sulfur Dioxide Monoxide Particulates
Volatile Organic Carbon Total Suspended
Exploratory Drilling -
Assumes four 10,000-foot
wells drilled at 90 days per
well; includes emissions from
support vessels on site and in
transit.
28.0 175.6 14.0 34.0 14.5
Platform Installation -
Includes emissions from
support vessels.
8.5 192.0 13.0 34.4 10.7
Pipeline Installation -
Includes emissions from
support vessels.
1.8 31.6 2.1 6.1 2.0
Development Drilling -
Assumes eight 10,000-foot
wells drilled per year; includes
emissions from support
vessels.
7.9 106.2 4.6 40.4 5.1
Offshore Platform -
Assumes annual production of
4.38 million barrels of oil and
5,840 million cubic feet of
natural gas.
25.7 99.0 0.7 69.3 5.5
Support Vessels -
Assumes one crew boat trip
and one supply boat every 2
days; includes emissions in
transit for 50-mile round trip.
0.9 42.4 2.9 6.4 1.9
Onshore Gas Processing -
Assumes processing of 21,900
million cubic feet of natural gas
annually.
13.6 39.8 21.0 4.8 3.5
Notes: The number of exploratory and development wells drilled annually in the Gulf of Mexico Offshore and onshore in the United States is much
larger than in the California Offshore. Total U.S. exploratory wells numbered 3,024 in 1997 while developmental wells numbered 23,453 (Energy
Information Administration, Monthly Energy Review, Table 5.2). Offshore operations in the Gulf of Mexico include emissions from helicopter crew
support flights as well as crew and supply boats. Onshore drilling includes emissions during construction of drilling pads and access roads.
Sources: Nitrogen Oxides: Radian, “Assessment of Nox Control Measures for Diesel Engines on Offshore Exploratory Vessels and Rigs - Final
Report” presented to Joint Industries Board (1982). Other Emissions: Form and Substance, Inc. for Minerals Management Service, A Handbook
for Estimating the Potential Air Quality Impacts Associated with Oil and Gas Development Off California (October 1983).
Disposal of Produced Water
Coproduction of a variable amount of water with the gas is
unavoidable at most locations. Because the water is usually
salty, its raw disposal or unintentional spillage on land
normally interferes with plant growth. Since the produced
water represents the largest volume waste stream generated
by exploration and production activities, its disposal is a
significant problem for the industry. The disposal process
varies depending on whether the well is onshore or
offshore, the local requirements, and the composition of the
produced fluids. Most onshore-produced water is disposed
of by pumping it back into the subsurface through on-site
injection wells. In some parts of the United States, injection
is not practical or economically viable and the produced
water is therefore piped or trucked to an off-site treatment
Energy Information Administration
66 Natural Gas 1998: Issues and Trends
facility. The disposal methods used by commercial disposal
companies include injection, evaporation, and treatment
followed by surface discharge. For example, the water
produced from onshore coal bed methane wells in Alabama
is disposed of by land application or by discharge into
streams after treatment; because of the elevated levels of
total dissolved solids, the water is tested by biomonitoring
for acute toxicity.29
Offshore, during a typical year of operations in the Gulf of
Mexico, it is estimated that approximately 685,000 barrels
of produced water are discharged, about half of which is
piped to onshore locations where it is treated and
subsequently discharged to onshore waters.30 Studies have
found few impacts of produced water disposal in the deeper
waters of the Gulf of Mexico or off Southern California. In
very shallow coastal areas (2 to 3 meters deep), more
extensive impacts from long-term discharges are
suggested.31 One of the original environmental concerns
regarding oil and gas drilling and production involves
undesirable movement of fluids along the well bore from
deeper, often salty, formations to formations near the
surface that contain fresh water. Operators are generally
required to cement casing from the wellhead through all
rock layers containing fresh water. While oil will obviously
contaminate fresh groundwater, entry of natural gas into
fresh water zones used for human or agricultural supply
will not, but it can create an explosion or suffocation risk.
Downhole separators are a new technology that promises to
reduce the environmental risk from produced water as well
as reduce industry’s cost of handling it. These devices
separate oil and gas from produced water within the well
bore, such that most of the produced water can be safely
injected into a subsurface formation without ever being
brought to the surface.
Condensate Production Hazards
There are an estimated 13,000 condensate tank batteries
which separate, upgrade, store, and transfer condensate
streams from natural gas produced in the United States and
its offshore areas.32 The separation is done using glycol
dehydration units, which the EPA has identified as a
potential source of hazardous air pollutants (as well as
tanks and vessels storing volatile oils, condensate, and
similar hydrocarbon liquids). The EPA has published
a Notice of Proposed Rulemaking seeking to reduce these
emissions by 57 percent for oil and natural gas production
facilities and by 36 percent from glycol dehydration units
in natural gas transmission and storage facilities. The final
rule is not expected until May 1999.
Venting, Flaring, and Fugitive Emissions
It is sometimes necessary either to vent produced gas into
the atmosphere or to flare (burn) it. Worldwide, most
venting and flaring occurs when the cost of transporting
and marketing gas co-produced from crude oil reservoirs
exceeds the netback price received for the gas. This practice
is by no means as common in the United States as it was a
few decades ago when oil was the primary valuable product
and there was no market for much of the co-produced
natural gas until the interstate pipeline system was
developed after World War II. The minor venting and
flaring that does occur now is regulated by the States and
may happen at several locations: the well gas separator, the
lease tank battery gas separator, or a downstream natural
gas plant.
The total amount of methane vented in 1996, 1.14 million
metric tons, was the second largest component of methane
emissions from natural gas operations (Table 5).
Throughout the entire process of producing, refining, and
distributing natural gas there are losses or fugitive
emissions. Production operations account for about
30 percent of the fugitive emissions, while transmission,
storage, and distribution account for about 53 percent. All
systems of pipes that transmit any fluid are subject to leaks.
In the case of natural gas, any leak will escape to the
atmosphere. The total methane emissions from all natural
gas operations in 1996 was 6.66 million metric tons, or
22 percent of all U.S. anthropogenic methane emissions.
When weighted by the global warming potential of
29K.R. Drotter, D.R. Mount, and S.J. Patti, “Biomonitoring of Coalbed
Methane Produced Water from the Cedar Cove Degasification Field,
Alabama,” in Proceedings of the 1989 Coalbed Methane Symposium, The
University of Alabama (April 17-20, 1989), p. 363.
30U.S. Department of Interior, National Oceanic and Atmospheric
Administration, Gianessi and Arnold, “The Discharge of Water Pollutants
from Oil and Gas Explorations and Production Activities in the GOM
Region” (April 1982), as cited in “Oil and Gas Program: Cumulative Effects,”
U.S. Department of the Interior, Minerals Management Service, Outer
Continental Shelf Report, MMS 88-0005 (1988), p. V-19.
31J.G. Mackin, “A Study of the Effect of Oilfield Brine Effluents on
Benthic Communities in Texas Estuaries” (College Station, TX, Texas A&M Environmental Protection Agency, Federal Register Notice, Part II,
Research Foundation, 1971), Proj. 735, p. 72, cited by Minerals Management 40 CFR Part 63, National Emissions Standards for Hazardous Air Pollutants:
Service in “Oil and Gas Program: Cumulative Effects,” Outer Continental Oil and Natural Gas Production and Natural Gas Transmission and Storage;
Shelf Report (1988). Proposed Rule (February 6, 1998), p. 6292.
32
Energy Information Administration
Natural Gas 1998: Issues and Trends 67
Table 5. U.S. Methane Emissions by Source, 1989-1996
(Million Metric Tons of Methane)
Source 1989 1990 1991 1992 1993 1994 1995 1996
Natural Gas Operations
Natural Gas Wellhead Production 0.28 0.29 0.30 0.30 0.30 0.31 0.30 0.32
Gathering Pipelines 1.08 1.07 1.03 1.03 0.92 0.84 0.74 0.74
Gas-Processing Plants 0.55 0.62 0.69 0.68 0.70 0.70 0.72 0.72
Heaters, Separators, etc. 0.17 0.17 0.17 0.17 0.18 0.19 0.19 0.19
Total Production 2.08 2.15 2.19 2.18 2.10 2.04 1.96 1.97
Gas Venting 0.77 0.75 0.81 0.83 0.97 1.01 0.68 1.14
Gas Transmission and Distribution 3.51 3.56 3.60 3.64 3.57 3.56 3.55 3.55
Total Natural Gas Operations 6.36 6.46 6.60 6.65 6.64 6.61 6.19 6.66
Natural Gas Stationary End-Use Combustion
Residential 0.005 0.005 0.005 0.005 0.005 0.005 0.005 0.005
Commercial 0.004 0.003 0.004 0.004 0.004 0.004 0.004 0.004
Industrial 0.012 0.013 0.013 0.013 0.014 0.014 0.015 0.015
Electric Utility * * * * * * * *
Total Natural Gas Combustion 0.021 0.021 0.022 0.022 0.023 0.023 0.024 0.024
Total from Natural Gas 6.381 6.481 6.622 6.672 6.663 6.633 6.214 6.684
Percent of U.S. Methane Emissions 20% 21% 21% 21% 22% 21% 20% 20%
Other Energy Sources
Coal Mining 4.31 4.63 4.38 4.28 3.50 3.90 3.98 3.93
Oil Well Production 0.04 0.04 0.04 0.04 0.04 0.04 0.04 0.04
Oil Refining and Transportation 0.08 0.08 0.08 0.08 0.08 0.09 0.09 0.09
Non-Natural-Gas Stationary Combustion 0.80 0.50 0.53 0.55 0.48 0.47 0.52 0.52
Mobile Sources 0.29 0.27 0.26 0.26 0.25 0.24 0.25 0.25
Total Other Energy 5.52 5.55 5.29 5.21 4.35 4.74 4.88 4.83
Non-Energy Sources
Waste Management 11.04 11.11 11.00 10.89 10.83 10.73 10.60 10.44
Agricultural Sources 8.18 8.29 8.55 8.77 8.79 9.11 9.05 8.75
Other Industrial Processes 0.12 0.12 0.11 0.12 0.12 0.13 0.13 0.13
Total Non-Energy 19.34 19.52 19.66 19.78 19.74 19.97 19.78 19.32
Total U.S. Methane Emissions 31.29 31.59 31.63 31.74 30.82 31.38 30.93 30.90
*Less than 500 metric tons of methane.
Notes: Data for 1997 from Energy Information Administration (EIA), Emissions of Greenhouse Gases in the United States 1997 (October 1998)
were not used because the report groups gas operations in a less detailed format. The report states that U.S. methane emissions totaled 29.11 million
metric tons in 1997, with natural gas systems accounting for 6.03 million metric tons, or 21 percent. Totals may not equal sum of components because
of independent rounding.
Source: EIA, Emissions of Greenhouse Gases in the United States 1996 (October 1997).
methane, this amounts to 2 percent of total U.S. greenhouse in Wyoming, and the San Juan Basin and Piceance Basin
gas emissions in 1996. coal bed gas fields, as a result of increased natural gas
Removal of Carbon Dioxide
Almost 500 billion cubic feet of the 24.2 trillion cubic feet
of gross withdrawals of natural gas in the United States in
1997 was in fact carbon dioxide (Table 6). The carbon
dioxide content of natural gas has been increasing over
recent years. This is mostly attributable to the growth of
production in fields with a relatively high carbon dioxide
component, such as in the Midwest, the Green River Basin
demand in recent years. Since 1990, the volume of carbon
dioxide coproduced with natural gas has risen by
23.4 percent.
More carbon dioxide (CO ) is produced with nonassociated 2
natural gas than with associated-dissolved natural gas
primarily because about 85 percent of U.S. gas production
is from nonassociated gas wells. Also, the chemical
processes involved in the formation of natural gas lead to
a higher CO content in nonassociated gas. In 1997, the 2
Energy Information Administration
68 Natural Gas 1998: Issues and Trends
Table 6. U.S. Carbon Dioxide Inherent in Domestic Natural Gas Production, 1990-1997
(Billion Cubic Feet, Unless Otherwise Noted)
Carbon Dioxide 1990 1991 1992 1993 1994 1995 1996 P1997
Produced
With Nonassociated Gas . . . . . . . . . . . . . . . . . . . 362.8 371.9 386.6 406.5 422.5 415.1 441.2 451.7
With Associated-Dissolved Gas . . . . . . . . . . . . . 14.7 15.0 15.8 15.8 14.8 14.2 13.8 14.1
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 377.6 386.9 402.4 422.3 437.3 429.3 455.0 465.8
Emitted
Production Activities . . . . . . . . . . . . . . . . . . . . . . 248.8 256.7 271.1 286.8 300.2 293.8 312.9 321.3
Pipeline Consumption . . . . . . . . . . . . . . . . . . . . . 5.4 4.9 4.8 5.1 5.6 5.7 5.8 5.8
End-Use Consumption . . . . . . . . . . . . . . . . . . . . 123.4 125.4 126.4 130.5 131.5 129.8 136.3 138.7
Total1 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 377.6 386.9 402.4 422.3 437.3 429.3 455.0 465.8
Total (Million Metric Tons of Carbon)2 . . . . . . . . 5.4 5.6 5.8 6.1 6.3 6.2 6.5 6.7
P = Preliminary data.
1Includes small amount carbon dioxide reinjected in Texas and Wyoming that is ultimately retained in the reservoir.
2Energy Information Administration, Emissions of Greenhouse Gases in the United States, 1997 (October 1998), p. 119.
Note: Totals may not equal sum of components because of independent rounding.
Source: Energy Information Administration, Office of Oil and Gas estimates, unless otherwise noted.
CO component of nonassociated gas produced was sometimes accumulate naturally occurring radioactive 2
2.5 percent as compared with 0.2 percent for associated- materials (NORM). Over a 20-year period, the
dissolved natural gas. Environmental Protection Agency estimates that the
The CO content of produced natural gas has numerous United States resulted in accumulation of 13 million metric 2
possible dispositions. For example, it can be left in the tons of NORM, as opposed to 1.7 billion tons in coal ash
natural gas that is returned to reservoirs to repressurize and more than 21 billion metric tons associated with metal,
them, thereby increasing the oil recovery factor, or it can be uranium, and phosphate mining and processing. NORM
left in the natural gas used for fuel in well, field, and lease can accumulate as scale or sludge in natural gas well
operations, or vented, etc. When processing of the raw casing, production tubing, surface equipment, gas gathering
natural gas stream is economically warranted, the CO is pipelines, and by-product waste streams. NORM 2
typically extracted by amine scrubbing and then vented to concentrations vary from background levels to levels
the atmosphere. The remaining carbon dioxide left in the exceeding those of some uranium mill tailings.
finished natural gas stream becomes a fugitive emission Traditionally, these materials have been regulated by the
somewhere during transmission, distribution or States.
consumption.
Of the 500 billion cubic feet of carbon dioxide produced contaminated casing and pipes to ensure that they are not
along with U.S. natural gas (Table 1), most is emitted to the converted into such things as furniture or playground
atmosphere. Almost 69 percent of carbon dioxide emissions
occur during gas production, with the remainder in
transmission, distribution, and consumption. The largest
single point of emissions is at natural gas plants, where at
least 200 billion cubic feet is emitted.33
Ancillary Production Activities
Gas exploration and production also result in a number of
other, relatively minor environmental consequences. For
example, gas production and processing operations
combined production of natural gas and crude oil in the
34
35
36
Proper precautions must be taken during disposal of
33Energy Information Administration, Office of Oil and Gas analysis Generation Most Cost-Effective Approach,” The American Oil & Gas
(September 1998). Reporter (December 1995), p. 101.
34Environmental Protection Agency, “Disposal of Naturally Occurring
and Accelerator-Produced Radioactive Materials,” EPA 402-K-94-001
(August 1994), <http://www.epa.gov/radiation/radwaste radwaste/narm.htm>.
35The sources of most of the radioactivity are isotopes of uranium-238
and thorium-232 which are naturally present in the subsurface formations
from which natural gas is produced. The primary radionuclides of concern are
radium-226 in the uranium-238 decay series and radium-228 in the thorium-
232 decay series. Other radionuclides of concern include those resulting from
the decay of radon-226 and radon-228, such as radon-222. Pipe scale and
sludge accumulations are dominated by radium-226 and radium-228, while
deposits on the interior surfaces of gas plant equipment are predominantly
lead-210 and polonium-210.
36Stephen A. Marinello and Mel B. Hebert, “Minimizing NORM
Energy Information Administration
Natural Gas 1998: Issues and Trends 69
equipment. The production waste streams most likely to be to remove the heavier hydrocarbons such as ethane,
contaminated by elevated radium concentrations include propane, pentanes, and hexanes, as well as contaminants
produced water, scale, and sludge. Spillage or intentional such as carbon dioxide and water, in order to bring the
release of these waste streams to the ground can result in natural gas stream into conformity with pipeline Btu
NORM-contaminated soils that must also be disposed of. content and other specifications. Typical processes
Most produced water containing NORM is disposed of on- performed by a gas plant are separation of the heavier-thansite
through injection wells for onshore locations and is methane hydrocarbons as liquefied petroleum gases,
discharged into the sea at offshore locations. Other types of stabilization of condensate by removal of lighter
NORM waste are presently disposed of at gas and oil hydrocarbons from the condensate stream, gas sweetening,
production sites and at off-site commercial disposal and consequent sulfur production and dehydration
facilities, mostly by underground injection. Smaller sufficient to avoid formation of methane hydrates in the
quantities of NORM are disposed of through burial in downstream pipeline. The EPA-identified hazardous air
landfills, encapsulation inside the casing of plugged and pollutant (HAP) emission points at natural gas processing
abandoned wells, or land spreading. plants are the glycol dehydration unit reboiler vent, storage
The physical appearance of a drilling rig or a wellhead is hydrocarbon streams that contain HAP constituents. Other
offensive to some people. In the oil-productive urban potential HAP emission points are the tail gas streams from
portions of onshore California, drilling rigs and wellheads amine-treating processes and sulfur recovery units.
are routinely hidden inside mock buildings in part for this
reason and in part to muffle the noise of operations. Methods vary for removing natural gas contaminants, such
Unfortunately an offshore platform cannot be hidden in the as hydrogen sulfide gas, carbon dioxide gas, nitrogen, and
same way. Aside from this “viewshed” issue, an offshore water. Commonly the hydrogen sulfide is converted to solid
rig precludes commercial fishing operations on an average sulfur for sale. Likewise the carbons and nitrogen are
of 500 acres because of it and its anchors’ presence. separated for sale to the 37 extent economically possible but
Offshore noise and light pollution are also a concern otherwise the gases are vented, while the water is treated
because noise can carry for long distances over and before release. Compressor operation at gas plants has a
underwater and offshore rigs and platforms operate round- similar impact to that of compressors installed at other
the-clock and are very well-lit at night. locations.
When drilling is conducted in remote areas on land, the
roads and airfields constructed by the well operators can
later provide easier public access for other purposes such as
hunting, fishing, and other outdoor activities unless special
provisions are made to prevent it. Access is generally a
bigger problem relative to oil wells since the transportation
cost per unit of value for natural gas is higher than that for
crude oil, which makes natural gas development in remote
areas less likely.
Natural Gas Processing
The processing of natural gas poses low environmental risk, pipelining, and disposal according to State or local
primarily because natural gas has a simple and regulations. In near-offshore areas such as the Mississippi
comparatively pure composition. There are 697 natural gas River Delta, canals have to be dredged to permit movement
processing facilities in the United States.38 Their purpose is of barge-mounted oil and gas drilling rigs and the laying of
39
tanks,40 and equipment leaks from components handling
Pipeline Construction and Expansion
Gas gathering pipeline systems move natural gas from the
well to a gas plant or transmission pipeline. The diameter of
the gathering pipe depends on the number and
deliverability of the wells served. Construction involves
clearing and grading right-of-way (ROW), trenching, pipe
welding and coating, pipe burial, and restoration of the
disturbed surface (although gathering pipelines are
sometimes laid on the ground surface). Operation of the
system involves supporting compressor stations and, in the
case of water-producing wells, water collection, pumping,
oil and gas gathering pipelines.
37U.S. Department of the Interior, Minerals Management Service, “Oil
and Gas Program: Cumulative Effects,” Outer Continental Shelf Report, H.D. Beggs, Gas Production Operations (Tulsa, OK: OGCI
MMS 88-0005 (1988). Publications, November 1995), pp. 219-222.
38Energy Information Administration, U.S. Crude Oil, Natural Gas, and Particularly those that handle volatile oil and condensates, which may
Natural Gas Liquids Reserves, 1997 Annual Report, DOE/EIA-0216(97) be significant contributors to overall hazardous air pollutant emissions
(Washington, DC, December 1998). because of flash emissions.
39
40
Energy Information Administration
70 Natural Gas 1998: Issues and Trends
The environmental impacts of transmission pipeline nitrogen oxides (NO ) and other gases during compressor
construction and operation are considered by the Federal operations. A transmission compressor station powered by
Energy Regulatory Commission prior to approval of natural gas has been estimated to produce 1.50 grams of
construction. About 300,000 miles of high-pressure NO per baseplate horsepower per hour (g/bhp-hr),
transmission pipelines are in place in the United States and 2.30 g/bhp-hr of carbon monoxide, and 1.50 g/bhp-hr of
its offshore areas. The construction ROW on land is volatile organic compounds. Methane leakage also occurs
commonly 75 to 100 feet wide along the length of the (Table 5). Significant reductions in methane leakage have
pipeline; this is the area disturbed by clearing and grading, occurred by converting wet (oil) shaft seals to dry (hightrenching,
soil storage, pipe storage, vehicle movement, pressure gas) shaft seals, which reduces the leakage rate
pipe burial, trench in-filling, and surface restoration, which range from 40 to 200 standard cubic feet (scf) per minute to
is between 9.1 and 12.1 acres per mile of pipe. In at most 6 scf per minute.
agricultural areas, it may take 1 to 3 years for cropland to
return to its former productivity after pipeline installation. Some transmission pipelines used polychlorinated
The permanent ROW on land is typically 50 to 75 feet wide biphenyls (PCBs) as lubricants in their compressors prior to
times the length of the pipeline. This is the area needed by 1976 when their manufacture was banned by the Toxic
the operator for routine inspection and maintenance Substance Control Act. The PCBs are a group of aromatic
operations, occupying from 6.1 acres to 9.1 acres per mile organic compounds that have inherent thermal and
of pipe.41 For every mile of offshore pipeline constructed on chemical stability but are quite toxic. Unfortunately, they
non-rocky sea floors, about 6 acres of sea bottom are diffused out of the compressors into the pipelines of those
disturbed and 2,300 to 6,000 cubic yards of sediment systems that utilized them; their cleanup has been a
displaced.42 significant problem. Research is continuing into methods
Pipeline Operations
Valves are installed along the pipeline to allow isolation of
leaking or failed segments of the line or complete shutdown The construction and operations associated with
should that become necessary. The pipe is generally underground natural gas storage also have environmental
brought to the surface so that the valve can be easily impacts. There are about 410 underground gas storage
reached and observed; siting is commonly in areas facilities in the United States, which have been variously
accessible by road but away from residential areas. The developed in former oil or natural gas producing reservoirs,
EPA has identified leaking valves as a potential hazardous in aquifers, and in man-made cavities in salt deposits.
air pollutant emission point. It has also identified pipeline
“pigging” operations and the storage of resulting wastes as Storage well drilling has a similar impact to that of drilling
potential hazardous air pollutant emission points. Pigging production wells with the exception that the geology is
operations are performed to inspect and clean the interior of often better known and the drilling is therefore less risky.
pipelines and entail safe disposal of the removed solid and In developing storage facilities at an aquifer or abandoned
liquid contaminants. oil or gas reservoir, horizontal wells have recently been
Compressor stations (about 1,900 of them in the United total drilling. If a salt deposit is being developed for
States)43 are also located along the route of the pipeline to storage, the salt water disposal can be into adjacent
ensure efficient movement of the gas. Because the location underground reservoirs or into the surface water
of a compressor station need not be precise, it can usually
be sited so as to reduce its impact on the human or natural
environment. However, there are unavoidable emissions of
x
x
44
45
for removal of the PCBs.
Underground Storage Operations
46
utilized to increase the input/output capacity and minimize
41Federal Energy Regulatory Commission, Pony Express Pipeline Project STAR Partners, Replacing Wet Seals with Dry Seals in Centrifugal
Environmental Assessment, Docket No. CP96-477-000 (April 1997), p. 2-20. Compressors,” Executive Summary, <http://www.epa.gov/gasstar/ sealsprn.
42Minerals Management Service, “Oil and Gas Program: Cumulative htm>.
Effects,” MMS 88-0005 (1988), pp. V-23 and V-20. A body of rock that is sufficiently permeable to conduct ground water
43Environmental Protection Agency, Federal Register Notice, Part II, and to yield economically significant quantities of water to wells and springs,
40 CFR Part 63, National Emissions Standards for Hazardous Air Pollutants: although they do not do the latter in the vicinity of a storage site. Robert L.
Oil and Natural Gas Production and Natural Gas Transmission and Storage; Bates and Julia A. Jackson, American Geological Institute, Dictionary of
Proposed Rule (February 6, 1998), p. 6292. Geological Terms, 3rd ed. (New York: Doubleday, 1983), p. 26.
44Federal Energy Regulatory Commission, Pony Express Pipeline Project
Environmental Assessment, Docket No. CP96-477-000, p. 3-33.
45Environmental Protection Agency, “Lessons Learned from Natural Gas
46
Energy Information Administration
Natural Gas 1998: Issues and Trends 71
environment under permitted conditions. The laying of ignitable by any flame, spark, or electrostatic discharge that
storage field pipelines has a similar effect as that of gas comes in contact with it. Nevertheless, the local distribution
gathering pipelines, but usually occurs in a much smaller of coal or fuel oil for commercial or residential use is
area and away from populated areas and sensitive habitats. significantly less energy efficient, and in the case of oil
The establishment of underground storage facilities at potentially more environmentally hazardous than is that of
depleted production field sites sometimes entails little in the natural gas.
way of additional disturbance.
The environmental impacts associated with storage
compressor facilities are similar to those for gathering and
mainline compressor installations. Dehydration units
located in storage fields are noted by EPA as a potential
source of hazardous air pollutants. It is common practice to
“blow” down production wells (often annually) when a
storage reservoir is developed in an aquifer or an
abandoned oil or gas reservoir. This practice clears loose
particles from the interstices of the storage reservoir rock
adjacent to the well bore, thereby restoring the rock’s
permeability and the maximum flow rate. However, this
practice produces a noise effect and the need to flare the
rapidly delivered gas.
Natural Gas Distribution
The local natural gas distribution company (LDC) takes gas
from the intra- or interstate pipeline company serving its
area. Facilities operated by the LDC include pressure
reduction facilities, odorant storage and insertion facilities,
and the small-diameter local distribution pipeline network
with its attendant valves and meters. Line losses are more
apparent in the LDCs’ pipelines than elsewhere, as the
odorant has been added and leaks can be detected by the
human nose. Line losses are also more dangerous in
distribution networks since built-up areas have many
enclosed spaces, and their infusion with leaked gas can
produce an explosive mixture of natural gas and air
Outlook
According to EIA’s Annual Energy Outlook 1999 reference
case, natural gas consumption for electricity generation
nearly triples, from 3.3 trillion cubic feet (Tcf) in 1997 to
9.2 Tcf, by 2020. Gas-fired generation is the economical
choice for construction of new power generation units
through 2010, when capital, operating, and fuel costs are
considered. Natural gas 47 consumption and emissions are
projected to increase more rapidly than other fossil fuels, at
average annual rates of 1.7 percent through 2020.48
However, this represents reductions in total carbon
emissions derived from the environmental advantages of
natural gas.
Concern about global warming and further deterioration of
the environment caused by escalating industrial expansion
and other development is being addressed by worldwide
initiatives (e.g., the Kyoto Protocol) that seek a decrease in
emissions of greenhouse gases and other pollutants.
Natural gas is expected to play a key role in strategies to
lower carbon emissions, because it allows fuel users to
consume the same Btu level while less carbon is emitted. If
carbon-reduction measures are implemented, EIA projects
in its Kyoto Protocol analysis that, by 2010, natural gas
demand would increase by 2 to 12 percent over otherwise
expected levels.49 Emissions from natural gas consumption
would also rise, but the natural gas share of total emissions
would increase only slightly.
47Energy Information Administration, Annual Energy Outlook 1999,
DOE/EIA-0383(99) (Washington, DC, December 1998), p. 82.
48Energy Information Administration, Annual Energy Outlook 1999, p.
85.
49Energy Information Administration, Impacts of the Kyoto Protocol on
U.S. Energy Markets and Economic Activity, SR/OIAF/98-03 (Washington,
DC, October 1998), pp. xix and 95.
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