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24
Energy Supply Systems
Energy supply can come from a wide variety of systems. Since
most of them are discussed extensively in the technical literature,
the panel does not attempt here to provide a comprehensive review.
Rather, the panel indicates the range of possible energy supply
systems in the United States and their implications for greenhouse
gas emissions at the current time. The panel leaves to more
specialized analyses the detailed consideration of system design
and selection. Projections as to the cost and path of technological
development of various energy supply systems in the future are not
attempted, but are discussed generally in terms of their relevance
to greenhouse warming.
Our energy supply is currently obtained in basically three ways:
(1) combustion of fossil fuels such as oil, natural gas, and coal;
(2) nuclear fission; and (3) other nonfossil-fuel-based sources
such as biomass and hydroelectric power. The level at which we use
each of these primary energy sources has a major impact on
greenhouse gas emissions, primarily because of the differing levels
of CO2 that these sources introduce
into the atmosphere.
It is particularly relevant to examine how fossil fuels are used
since they are currently our principal source of energy. One
estimate of the carbon contained in fossil fuels, and hence of the
potential for mankind to alter the CO2 concentration of the atmosphere, is
given in Table 24.1 (Fulkerson et al., 1989). The atmosphere
currently contains about 750 Gt of carbon as CO21Figure 24.1
documents the course of fossil fuel burning over the last 30 years
and the simultaneous increase in the mass of atmospheric CO2.
The mass of carbon in the recoverable resources of conventional
oil and natural gas (250 Gt C, see Table 24.1) is notably smaller
than the mass of carbon in the atmosphere (750 Gt C, where 1 ppmv
of CO2 in the atmosphere is equal to
2.13 Gt C). Consequently, the CO2
doubling so often
Page 331
TABLE 24.1 Estimated Remaining Recoverable World
Resources of Fossil Fuels and Their Potential Effect on Atmospheric
CO2
Energy Content
Carbon Content
CO2 Concentration
Increase (ppmv)
Fuel
Quantity
(1018 Btu)
(Gt)
ƒ=0.4
ƒ=0.55
ƒ=0.7
Oil
1.25 × 1012
barrels
7
130
24
34
43
(0.2 × 1012
m3)
Natural Gas
8,200 TCF
8
120
23
31
39
(232 × 1012
m3)
Coal
5,500 Gt
153
3,850
723
994
1,265
TOTAL (rounded off)
168
4,100
770
1,060
1,350
NOTE: Abbreviations: ppmv = parts per million by
volume, TCF = trillion cubic feet, and ƒ = fraction of CO2 retained in the atmosphere. In addition
to these amounts of carbon, comparable or larger amounts may be
available in other fossil resources such as heavy oils, oil shale,
tar sand, and lower grades of coal. Thus the quantity of carbon
ultimately released to the atmosphere as CO2 could conceivably be 1.5 to 2 times the
total shown in the table.
SOURCE: Fulkerson et al. (1989).
FIGURE 24.1 Cumulative emissions of CO2 from fossil fuel burning since 1959 and
observed increases in the atmosphere at Mauna Loa.
SOURCES: Data are
from Keeling et al. (1989); Marland (1990).
Page 332
examined in climate models could not be accomplished even if all
of the conventional oil and gas were burned. The world recoverable
resources of coal, on the other hand, are very large. Over the long
term, if mankind is to produce perturbations of atmospheric CO2 up to and beyond a doubling, it will be
because of the oxidation of large quantities of coal and low-grade,
unconventional fuels such as oil shale. Estimates of ultimately
recoverable resources are, of course, very uncertain. As currently
understood, world recoverable resources of coal are heavily
concentrated in three large northern hemisphere nations: the United
States, the former USSR, and the People's Republic of China. These
three nations contain an estimated 87 percent of world recoverable
resources of coal.
As primary sources of usable energy, fossil fuels release heat
through the exothermic reaction of atmospheric oxygen with the
carbon and hydrogen of fuel. The consequent release of CO2 is fundamentally different from many
traditional pollutant releases in which a low grade (e.g., trace
metal) or otherwise unintended (e.g., CO or SO2) by-product is released to the
environment or a purposeful product reaches beyond its intended
application (e.g., pesticides). The emission of CO2 is an essential consequence of burning
fossil fuels.
Largely because the carbon to hydrogen ratios of fossil fuels
differ, their rate of CO2 production
per unit of useful energy differs. Natural gas is principally
CH4, with a 1:4 ratio of carbon to
hydrogen, and it releases 13.8 kg C per gigajoule (GJ). Although
coal has a wide range of chemical compositions, it contains less
hydrogen than natural gas, and to a first approximation the heating
value varies with the carbon content. The value 24.1 kg C/GJ can be
used to estimate the CO2 release on
combustion for most coals, although for very low grade coals this
ratio increases slightly. Liquid petroleum products fall somewhere
in between natural gas and coal. The CO2 release for average world crude oil (and
hence the average for a mixture for all products) can be taken at
about 19.9 kg C/GJ. For a discrete refined product, the value
differs: for example, 18.5 is appropriate for automotive gasoline
(Marland, 1983).
While CO2 can be intimately and
accurately related to fossil fuel combustion, there are other, less
well characterized, greenhouse gas emissions from the fossil fuel
cycle. The production, processing, and distribution of natural gas
inevitably allow some CH4 to escape
to the atmosphere, and the natural gas that is associated with
petroleum production can result in venting (as CH4) or flaring (to produce CO2). Methane also exists dispersed in coal
seams and is generally released to the atmosphere during coal
mining.
Nitrous oxide (N2O) emissions
from fossil fuel combustion may be very small. Recent studies
(Muzio et al., 1989) have cast doubt on all earlier measurements,
and it is not now clear how much N2O
is released during combustion processes. (Note that N2O is different from the more common
oxides of nitrogen (NOx)—NO and NO2—associated with fuel
combustion.)
Page 333
Recent Trends
An initial step in looking at recent trends is to review the
sources of the U.S. energy supply, and these are shown in Figure
24.2. Oil is the largest source of energy supply at 41 percent, and
coal is second at 23 percent. Renewables account for 8 percent,
with hydropower providing almost half
FIGURE 24.2 National energy supplies and the
renewable contributions.
SOURCE: Solar
Energy Research Institute (1990).
Page 334
of that. Biomass used in the industrial, buildings, and
electricity sectors provides roughly the same amount of energy as
hydropower. Very little energy currently comes from solar, wind,
geothermal, or other sources of renewable energy (Solar Energy
Research Institute, 1990).
Table 24.2 shows electricity generation and the carbon emissions
from generation in the United States in 1988. Coal is the largest
generation source of U.S. electricity at 57 percent, with nuclear
second at 19.5 percent. Renewables represent only a small portion
of U.S. electric power generation. Electricity generation in the
United States is responsible for approximately 35 percent of U.S.
CO2 emissions and 8 percent of
worldwide anthropogenic CO2
emissions (Edmonds et al., 1989).
To contrast the various energy systems and their greenhouse gas
implications, it is necessary to inventory full fuel cycle costs.
For a gasoline-powered automobile, for example, CO2 emissions are not simply those
discharged from the engine but also those CO2 (and other trace gas) emissions
discharged during petroleum exploration, production, refining, and
product distribution.
Although there are many difficulties in detail with using a
CO2 accounting, in theory
comparisons can be made. One estimate is that for every direct use
of liquid fuel, CO2 emissions
equivalent to those that would result from the use of an additional
11.8 percent of petroleum products are produced in activities
upstream from the final products at the refinery. Under this
accounting system, these greenhouse gas emissions should be
charged
TABLE 24.2 Electric Power Generation in the United
States, 1988
Fuel
Carbon Emissions (Million tons)a
Generation (Bk Wh)b
Percentage of Generation
Coal (758 × 106 short tons)
398 (85%)
1,538
57.0
Oil (248 × 106 barrels)
31 (7%)
149
5.5
Gas (2634 billion ft3)
39 (8%)
252
9.3
Nuclear
—
526
19.5
Hydroelectric
—
223
8.3
Renewables
Negligible
12
0.4
TOTAL
468
2,700
100.0
aThese are
net emissions at the point of power generation and do not include
emissions related to system capital or other portions of the fuel
cycle. The assumption is made that biomass fuels are raised in a
sustainable manner so that combustion releases are balanced by
photosynthetic capture. Tons are metric.
bBk Wh =
billion kilowatt-hours.
SOURCE: National Research Council (1990).
Page 335
at the point of product use. Similar values for natural gas and
coal are less well established but have been estimated at 18.8
percent for gas delivered to the customer and 2.2 percent for coal
at the minehead (Marland, 1983).
In the 1987 global economy, 95 percent of total commercial
energy (energy that is traded in commercial markets but not
including ''traditional fuels" such as wood) was produced from
fossil fuels. This varied from virtually 100 percent in some
resource-poor countries largely dependent on imported petroleum, to
62 percent for France (where 77 percent of electricity is from
nuclear plants) and 29 percent for Norway (where hydroelectric
plants contribute a large fraction of the total energy). The value
was 89 percent in the United States. (These fractions are based on
numbers from the United Nations, but they count nuclear power and
hydroelectricity at their conventional fuel equivalents by assuming
fuels could be converted to electricity at a 33 percent net plant
conversion efficiency.)
On the global scale, petroleum contributes the largest share (44
percent) of the energy from fossil fuels, with coal (32 percent)
and natural gas (24 percent) following, but coal is the dominant
fuel in a number of countries (China, India, and the former German
Democratic Republic). In the United States, 83 percent of coal is
used in electric power plants and another 5 percent is used in the
iron and steel industry (Organization for Economic Cooperation and
Development, 1987). The transportation sector is the largest user
of petroleum in the United States (62 percent), with the remainder
spread over many applications, including nonfuel applications (some
of which do not emit greenhouse gases). Twenty-five percent of U.S.
natural gas is used in residences, with another 17 percent used for
electric power generation and the remainder scattered throughout
the commercial and industrial sectors (U.S. Department of Energy,
1988).
Emission Control Methods
A number of alternatives are available for reducing net
greenhouse gas emissions from the production of energy. In this
chapter, the discussion is divided into two major topics. Energy
supply systems purely for electricity generation are discussed
first. Then energy supply systems on a broader basis are examined.
Some examples of existing efficient energy systems are given, and a
concept called integrated energy systems is discussed. The
relevance of new fuel supply and conversion options is treated in
this context. Following the descriptions of the technical options,
a separate section illustrates how the cost-effectiveness of
different options can be compared. Because of the number and
complexity of options available, it is not possible to make this
discussion comprehensive and all-inclusive. Rather the attempt here
is to convey a picture of the technological options available and
the methodology employed.
Page 336
Electricity Generation
Electricity can be generated from coal, oil, natural gas,
nuclear energy, and a variety of renewable forms of energy
including hydraulic resources, wind, geothermal, solar thermal, and
solar photovoltaic energy. With the exception of oil, each is
discussed below. Although oil historically has been used for power
generation in some regions of the United States (principally in the
Northeast), its use has declined dramatically in the past decade
and no significant increase is foreseen. The primary use of oil for
electricity and steam generation in the United States is in the
industrial sector, which is discussed in Chapter 22. The power
generation technology options discussed below for coal and natural
gas also are applicable to oil in many instances.
Coal
Coal is the most abundant fossil fuel resource in the United
States and is the principal fuel powering the economies of several
other nations including China and the former USSR. Coal is used
primarily for electric power generation, but also for industrial
process heat and, in some cases (mostly in developing countries),
domestic heating and cooking. Barring severe environmental
repercussions, coal is likely to continue to be a major energy
source for power generation and other energy needs well into the
twenty-first century.
From the point of view of greenhouse gas emissions, the
principal issues are the quantities of coal that will be used and
the efficiency of coal combustion and energy conversion.
Conventional pulverized-coal-fired power plants now being built are
capable of overall thermal efficiencies (the efficiency with which
coal is converted to electricity) of about 38 percent without
scrubbers (the SO2 removal systems
that reduce emissions of acid rain precursors but also reduce net
power plant efficiency). The average for all coal-fired power
plants now in place in the United States, however, is about 33
percent (U.S. Department of Energy, 1989).
Several technological developments hold promise for continued
improvement in coal-based electric power generation (Rubin, 1989).
Table 24.3 summarizes performance estimates by the Electric Power
Research Institute (EPRI) for several power generation options,
which range from improvements in current technology to newer
systems not yet commercially demonstrated (Electric Power Research
Institute, 1986).
Overall, efficiency improvements on the order of 10 percent or
more are expected from technological advances over the next decade.
The most promising near-term options include integrated
gasification combined cycle (IGCC) systems and pressurized
fluidized-bed combustion (PFBC) systems. The latter technology is
planned for demonstration in the United States
Page 337
TABLE 24.3 Efficiency of Coal-Based Power Generation
Systems
Technology
Heat Rate (Btu/kWh)a
Conventional coal-steam with wet limestone flue
gas desulfurization:
Supercritical boiler
9,660
Subcritical boiler
10,060
Advanced pulverized coal-steam with flue gas
desulfurization
8,830
Atmospheric fluidized-bed
10,000
Pressurized fluidized-bed combined cycle
8,980
Coal gasification combined cycle:
Current turbine
9,775
Advanced turbine
9,280
Gasification fuel cell combined cycle
7,130
Gasification combined cycle methanol
co-product
12,875
aThe
annual average heat rate, which is a reciprocal of efficiency, is
the performance measure most commonly used for utility systems.
Data are for an Illinois bituminous coal and a plant size of
approximately 500 MW.
SOURCE: EPRI (1986).
under the Department of Energy's (DOE's) Clean Coal Technology
Program, and other PFBC demonstration plants are being constructed
in Europe.
Integrated gasification combined cycle technology has been
demonstrated at the 100-MW scale at the Cool Water Facility
operated by Southern California Edison. Although a number of U.S.
utilities are studying the feasibility of building additional IGCC
capacity, that technology in most cases is not yet economically
competitive with conventional pulverized coal combustion. Advanced
IGCC designs employing the concept of "hot gas cleanup" (i.e.,
removing pollutants without having first to cool the flue gas) hold
promise of greater efficiency gains and lower cost (Bajura, 1989).
Such technologies are currently under development.
In the near term, boiler repowering, in which an older existing
unit is replaced with a more efficient new one, is another method
by which the overall efficiency of coal utilization can be
improved. In this type of application, atmospheric fluidized-bed
combustion (AFBC) units may be attractive because of their compact
size and fuel versatility. Several repowering projects are now
under way in the United States using AFBC boilers.
Page 338
As mentioned above, a negative impact on CO2 emission can result from the flue gas
desulfurization (FGD) systems, or "scrubbers," used to remove
SO2. Because the energy needed to
operate the scrubber reduces overall power plant efficiency,
CO2 emissions per unit of useful
electricity increase proportionately. Modern FGD systems require
only 1 to 2 percent of the power plant output for operation, down
by a factor of 2 from systems built in the early 1980s. This
improvement has resulted from more efficient scrubber designs and
the elimination of stack gas reheat systems.
Fluidized-bed combustion systems have a comparable loss of
thermal energy when limestone is used for SO2 control. The SO2 removal systems using lime or limestone
reagents (whether in scrubbers or fluidized beds) release
additional CO2 directly through the
chemistry of sulfur removal. This additional CO2 stream is small, however, in comparison
with the CO2 emissions from coal
combustion.
There are small differences in CO2 emissions due to differences in coal
quality. In general, coals with higher sulfur content emit less
CO2 per unit of energy, complicating
any policy designed to reduce both CO2 and SO2
emissions. High-rank bituminous coals produce 5 to 10 percent less
CO2 than do lower-rank subbituminous
and lignite coals (Winschel, 1990); however, most coals actually
burned at the present time fall within a narrower range of 2 to 3
percent. Thus the differences in CO2
emissions resulting from the combustion of different coal types are
roughly the same order of magnitude as the reductions anticipated
from near-term combustion efficiency improvements.
For the immediate future, perhaps the most cost-effective means
of CO2 reduction from existing
coal-fired power plants lies in heat rate (efficiency) improvements
achievable by improved plant maintenance and operation. EPRI
estimates that such measures could result in a 2 to 4 percent
reduction in current CO2 emissions
at a very small cost (Gluckman, 1990). The resulting efficiency
improvements have the potential for saving roughly 2 to 4 percent
in fuel consumption, offsetting the small costs that are incurred
(and perhaps even generating net additional revenues and thus
yielding a net negative cost of CO2
abatement). Heat rate improvements are actively being pursued by
many utilities today.
Finally, future developments for coal-fired power plants
conceivably could include control technology for the removal of
CO2 from flue gases. This option,
which could apply generally to fossil fuels, is discussed later in
this chapter.
Natural Gas
As pointed out previously, the combustion of natural gas emits
less CO2 than the combustion of coal
because of the higher ratio of hydrogen to
Page 339
carbon. There are a number of ways natural gas can be used in
place of coal for electricity generation.
Combined Cycle Systems In a gas turbine combined cycle
(GTCC) system, the exhaust from a gas turbine is fed into a
residual heat boiler that generates steam for a bottoming steam
turbine cycle. If natural gas is used to fuel the gas turbine, the
overall efficiency of the system can be slightly more than 50
percent. The capital cost of such a system is about $500/kW.
Combined cycle systems have not been considered a serious option in
the planning of future power generation until very recently,
largely because of the uncertainty in the availability of natural
gas and the poor reliability of GTCC systems in the past. The
latter was not due to inherent technical barriers but to a lack of
attention from the industry.
Two recent events changed the situation. First, EPRI, in
cooperation with Southern California Edison and Texaco, proposed
the organization of a consortium to develop a $300 million IGCC
system—the Cool Water project. For the first time, the issue
of the reliability of combined cycle systems received serious
attention. Second, Japan, in an effort to diversify energy sources,
ordered several gigawatts of combined cycle systems to use
liquefied natural gas.
Further, as discussed in a number of reports (e.g., Tabors and
Flagg, 1986), GTCC is competitive economically with alternative
forms of energy supply. The attractiveness of GTCCs, therefore, has
been broadly recognized both in its economics and in its potential
contribution to the reduction of greenhouse gases.
Other Natural Gas Options One of the most difficult
issues in the global greenhouse warming problem is how developing
nations can participate in mitigation efforts without damaging
their economic development. Some of these nations might require
options with capital costs even lower than those of GTCC. Steam
injection in aircraft-type gas turbines might be an option to
consider, even though the efficiency may be slightly lower
(Williams, 1989). For small plants, El-Masri (1988) has proposed a
regenerative system that is attractive from the viewpoints of both
cost and efficiency. This system has not yet been tried, but the
technical and economic basis is sufficiently sound to warrant
consideration. In addition, the Kalina cycle, a type of steam cycle
used in conjunction with a natural gas turbine, can have an
efficiency of more than 55 percent with today's commercial gas
turbines (Exergy Inc., 1989).
Nuclear Energy
Apart from the CO2 emitted in the
exploration, production, and enrichment of uranium, nuclear plants
do not emit CO2. Reactors based on
nuclear fission have operated for many years and provide a
significant contribution
