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7
Fossil-Fuel Energy
Total U.S. primary energy consumption in 2007 was about 100 quads, with fossil fuels—natural gas, petroleum, and coal—supplying about 85 percent, as shown in Table 7.1 (EIA, 2008a).1 Liquid fuels (derived primarily from petroleum) were the main contributors, accounting for 40 percent of total consumption (see Figure 1.2 in Chapter 1). This fossil-fuel dominance has held steady for decades.
Even more striking, each of the fossil fuels accounts for a major segment of an important end-use market. Petroleum supplies 98 percent of the energy used in the transportation market, natural gas provides 74 percent of the nonelectric energy used in the residential and commercial market, and coal furnishes 52 percent of the energy used to generate electricity. Only in the electricity market, where nuclear and renewable energy sources account for 29 percent of the total energy supply, do serious competitors to fossil fuels exist.2 Despite considerable efforts to expand biofuel production, for example, ethanol from corn provided only about 3 percent of the U.S. gasoline supply in 2005.
These distinctive structures exist because the attributes of liquid, gaseous, and solid fossil fuels closely match the needs of their respective end-use markets:
1
Worldwide, the dominance of fossil fuels is little different; they provided 86 percent of world primary energy consumption in 2004.
2
Oil and gas are the dominant suppliers of the industrial market, primarily for feedstocks in chemical production.
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TABLE 7.1 U.S. Energy Consumption by Energy Source in 2007
Energy Source
Consumption (quadrillion Btu [percent])
Petroleum
39.77 [39]
Natural gas
23.63 [23]
Coal
22.75 [22]
Nuclear power
8.46 [8.3]
Hydropower
2.45 [2.4]
Biomass
3.60 [3.5]
Other renewable energy
0.77 [0.008]
Other
0.11 [0.001]
Total
101.55
Note: Numbers have been rounded.
Source: EIA, 2009a.
Petroleum is easily stored and transported and has a relatively high energy density. These characteristics are well suited to the transportation market.
Natural gas burns cleanly, is easily transported by pipeline, and can be stored in salt domes and old gas fields for peak use. As a result, it is a desirable fuel for the geographically distributed residential and commercial markets.
Coal is abundant in the United States, is easily stored, and is less expensive, with lower price volatility than other fuels—attractive attributes for electricity generation.
Although the market-based reasons for using fossil fuels are thus very strong, U.S. reliance on this energy source carries some potentially adverse consequences. For one, reserves of petroleum—and, increasingly, of natural gas—are concentrated in only a few countries. In some cases, supplier nations have restricted supplies for nonmarket reasons. Moreover, such concentrations of production capacity, and the limited number of transportation routes from these facilities to their markets, create targets by which hostile states or nonstate actors may disrupt supplies. In either case, the security of petroleum and natural gas supplies is at risk, probably increasingly so.
A second concern is that the longer-term global demand for petroleum and
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natural gas is projected to grow faster than increases in production, resulting in tight market conditions and rising prices. The U.S. Energy Information Administration (EIA) and the International Energy Agency (IEA), along with other forecasters, do not anticipate that the factors underlying these market conditions will change anytime soon.3 Under such conditions, maintaining significant spare production capacity is difficult.
From the point of view of net consuming nations, the resulting price increases could accelerate an economically disruptive wealth transfer from consumers to producers. While the dependence of the U.S. economy on oil has changed little in recent decades—in 1990, 39.7 percent of U.S. energy consumption was petroleum; in 2007, it was 39.2 percent—U.S. dependence on imports has doubled over this period.
Finally, fossil fuels pollute the atmosphere when burned, and they have other adverse environmental effects as well. While emissions of SOx, NOx, particulates, and other atmospheric contaminants have been reduced (albeit with an increase in solid, liquid, or recyclable wastes, including ash residuals), little has been done so far to address carbon dioxide (CO2) emissions. U.S. energy use in 2007 was responsible for emissions of 6 billion tonnes of CO2 (6 Gt CO2). Of that amount, 43 percent came from petroleum, 36 percent from coal, and 21 percent from natural gas (EIA, 2008c). By market, the largest source was electric power generation (using coal and natural gas); it emitted some 2.4 Gt CO2. Transportation, dominated by petroleum but also including some natural gas, accounted for 2 Gt CO2. The remainder of the emissions resulted from industrial (1 Gt CO2), residential (0.35 Gt CO2), and commercial uses (0.25 Gt CO2).4 (See Figure 1.11 in Chapter 1.)
Thus the future of fossil fuels presents a serious dilemma for energy policy. On the one hand, because fossil fuels are well adapted to the needs of the market, a huge energy infrastructure has been put in place to take advantage of their value. The existing stocks of vehicles, home and business heating systems, and electric power stations were created with the expectation that petroleum, natural gas, and coal would be readily and reliably available. On the other hand, the
3
For the latest IEA forecast, see Energy Technology Perspectives 2008 (IEA, 2008a), p. 113ff. The downturn in the world economy apparent at the time of this writing will mitigate demand growth for a while, but the underlying determinants of demand remain in place.
4
Note that while electric power is used in industrial, residential, and commercial settings, it is aggregated under electric power generation.
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extraction and use of fossil fuels entail growing security, economic, and environmental risks. A crucial question, therefore, is whether this existing energy infrastructure can be supplied with liquid, gaseous, and solid fuels in the future at acceptable levels of such risks. If so, much of it can remain in place. If not, the embedded capital stock of technologies for energy production and use will need to change through a combination of market forces and policy choices.
Other chapters of this report discuss alternative pathways for providing the energy services that modern society demands. For example, the chapter on alternative transportation fuels (Chapter 5) provides an assessment of the technologies and environmental impacts of liquid fuels derived from biomass feedstocks, coal, or natural gas. This present chapter focuses on alternative ways of using fossil fuels to serve the existing energy-use infrastructure. Specifically, it explores:
The extent to which the U.S. endowment of fossil fuels is limited in its ability to meet future needs for liquid, gaseous, and solid fuels by means of conventional pathways.
New technologies that may become available for producing the desired form of fossil fuels. The focus in particular is on the generation of electricity from coal and natural gas with sharply reduced emissions of greenhouse gases, especially CO2.
Technologies and geologic settings suitable for the storage of CO2 produced from electricity generation and other industrial processes.
Environmental concerns that affect the future of fossil-fuel supply and use.
Given constraints on time and resources, the AEF Committee chose not to address issues relating to the current energy infrastructure, for example, the status of natural gas pipelines, oil refineries, rail and barge transportation for coal, and liquefied natural gas terminals.
OIL, GAS, AND COAL RESOURCES
Worldwide, the amount of oil, gas, and coal that can ultimately be produced is very large. Estimates of ultimately recoverable resources are uncertain, however, because they include not only those that are discovered though not yet economically or technically recoverable but also those that are yet to be discovered. Nev-
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ertheless, the potential is impressive. Roughly 3.3 trillion barrels of oil and 15,000 trillion cubic feet (Tcf) of natural gas are thought to be ultimately recoverable. By comparison, in 2006, world consumption of these resources was about 30 billion barrels of crude oil and 100 Tcf of gas. (See Tables 7.2, 7.3, and 7.4 for summaries of oil, gas, and coal statistics.)
Resources that are discovered, recoverable with current technology, commercially feasible, and remaining in the ground are classified as reserves. The size of
TABLE 7.2 Conventional Oil Resources, Reserves, and Production (billion barrels, variable years as noted)
United States
World
U.S. Percent of World Total
Resources
430a
3345b
13.0
Reservesc
29
1390
2.1
Annual production
2.5/yr
29.8/yr
8.4
Annual consumption
7.5/yr
31.1/yrd
24.1
aDOE, 2006a, available at fossil.energy.gov/programs/oilgas/eor/Undeveloped_Domestic_Oil_Resources_Provi.html.
bNPC, 2007, p. 97.
c2007 data from British Petroleum, 2008.
dAccording to British Petroleum, 2008, discrepancies between world production and consumption “are accounted for by stock changes; consumption of nonpetroleum additives and substitute fuels; and unavoidable disparities in the definition, measurement, or conversion of oil supply and demand data.”
TABLE 7.3 Natural Gas Resources, Reserves, and Production (trillion cubic feet, variable years as noted)
United States
World
U.S. Percent of World Total
Resources
1,525a
15,401b
9.4
Reservesc
211
6,263
3.4
Annual production
19.3/yr
104.1/yr
18.5
Annual consumptionc
23.1/yr
103.5/yrd
22.3
aPGC, 2006, available at www.mines.edu/research/pga/.
bNPC, 2007, p. 97.
c2007 data from British Petroleum, 2008.
dAccording to British Petroleum, 2008, discrepancies between world production and consumption are “due to variations in stocks at storage facilities and liquefaction plants, together with unavoidable disparities in the definition, measurement or conversion of gas supply and demand data.”
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TABLE 7.4 Coal Reserves and Production (million tonnes, variable years as noted)
United States
World
U.S. Percent of World Total
Resources
3,968,000a
9,218,000b
43.0
Reservesc
242,721
847,488
28.6
Annual productionc
1,039.2/yr
6,395.6/yr
16.2
Annual consumptionc
1,015.3/yr
6,481.1/yr
15.7
aEIA, 1999.
bHermann, 2006.
c2007 data from British Petroleum, 2008.
known reserves, while considerably smaller than the more speculative estimates of ultimately recoverable resources, is also large. British Petroleum has reported that proved reserves of oil in 2006 amounted to 1390 billion barrels and that proved natural gas reserves were 6263 Tcf (British Petroleum, 2007). World coal reserves were 900 billion tonnes, which is about 300 times the 2006 world coal consumption (British Petroleum, 2007).
Technology plays an important role in turning speculative resources into proved reserves. Sophisticated exploration and production methods for recovery of oil and natural gas are already commercially available, and the private sector is developing advanced versions of these techniques. The cumulative effect of continuing advances in exploration and production technology for oil and gas is that over the next 20 years much of the current resource base will become technically recoverable. (See Table 7.5 for a discussion of this technology.)
As noted previously, world reserves are annually producing about 30 billion barrels of oil and 104.1 Tcf of natural gas. The United States is the third-largest oil-producing country and the second-largest natural gas producer. Nevertheless, this country imports about 56 percent of its oil and about 14 percent of its natural gas.5 Import dependence, especially for oil, creates serious economic and security risks, as global oil and gas supplies may be influenced by restrictions imposed by governments, by the actions of the Organization of the Petroleum Exporting Countries (OPEC), or by disruptions due to political instability or regional conflict. For this reason, the capacity to maintain or increase domestic production is
5
Virtually all of the natural gas that the United States imports comes from Canada.
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TABLE 7.5 Summary of Highly Significant Oil Exploration and Production Technologies
Technology
Timeframe
Discussion
Big increase in controlled reservoir contact
2015
Technologies allowing a continuing increase in the number of strategically placed horizontal wells will allow a much greater commercial access to reserves.
Horizontal, multilateral, and fishbone wells
2020
Multiply placed drainholes from a main wellbore will further extend commercial access to reserves.
Arthroscopic well construction
2025
The ability to place drain holes to within feet of every hydrocarbon molecule in the formation allows the ultimate recovery.
SWEEP (see, access, move)
2020
The combined technologies (including the four immediately below) allowing us to see, access, and move the hydrocarbons in the optimum way will bring a big increase to recoverable reserves.
Smart well (injection and production)
2015
The ability to control what fluids go where (at the wellbore).
Reservoir characterization and simulation
2015
Extending current technology to include simultaneous inversion of all measurements with a forward model.
Reservoir vision and management in real time
2020
Combining reserve scale measurements (pressure, seismic, electromagnetic, and gravity) in a joint inversion, with uncertainty and without bias.
Mission control for everything
2020
A full representation and control of the full system (subsurface and surface) allowing true optimization.
CO2 flood mobility control
2020
Measurement and control of the CO2 flood front is critical to successful implementation.
Artificial lift
2030
Produce only wanted fluids to surface.
Drilling efficiency
2015
A further extension of gains already made.
Steam-assisted gravity drainage (SAGD) or steam and alkaline-surfactant-polymers (ASPs)
2030
Technologies to perfect and optimize SAGD operations (including the use of ASPs) will be key to widespread economic exploitation of heavy oil.
Arctic subsea-to-beach technology
2020
Ice scouring of the seafloor surface presents a huge challenge to conventional approaches to subsea and subsea-to-beach operations.
Faster and more affordable, higher-definition 3D seismic
2015
Quicker, better, cheaper, could extend the already impressive “specialized” technology in universal use.
Source: NPC , 2007, Topic Paper 19, “Conventional Oil and Gas,” Table V.1.
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a major concern for energy policy. Technical, environmental, and economic uncertainties, however, constrain the pace at which domestic oil and gas production can or will be increased. Accordingly, the following sections focus on the ability of domestic oil, natural gas, and coal sources to maintain or increase production. Tables 7.2 and 7.3 summarize the current levels of resources, reserves, and production for domestic oil and natural gas, and Table 7.4 reports reserves and production for coal.
Oil
While Table 7.2 summarizes estimates of the quantities of various types of oil resources in the United States, Table 7.6 disaggregates them. “Proved reserves” in Table 7.6 are those that can reasonably be recovered at costs low enough to allow economic production of the resource. The remaining estimated resources listed are called “technically recoverable”—that is, they are generally expected to be recoverable using currently available technology, but without regard to economic viability. In some cases, the estimates are for oil that is yet to be discovered. These estimates are obviously less certain than for those resources already discovered.
Table 7.6 lists estimates of the range of costs that might be incurred to produce each of the resources. The wide ranges of estimated costs reflect considerable uncertainty; costs vary widely, depending on the location, size, and depth of the resource and on many other factors. Finally, Table 7.6 also estimates the time period in which a reasonable quantity of the resource might be available for use. Here again, there is considerable uncertainty because of costs and other limitations, such as access to drilling or mining and environmental impacts.
The resources listed in Table 7.6 for light oil enhanced oil recovery (EOR) are those that could be recovered primarily by CO2 injection. Whereas conventional oil recovery processes (primary production under the natural pressure in the reservoir and water injection) typically recover about a third of the oil in place, this resource estimate is based on an assumption that total recovery in fields suited to CO2 injection would reach 50 percent. The total amount recovered in some reasonable time period is likely to be lower than the total listed, however. Not all fields will be large enough to warrant the investment required, and sufficient CO2 may not be available. Even so, the experience gained in operating CO2 EOR projects in west Texas over the last three decades has advanced the technology significantly. EOR projects can now be undertaken with confidence that high-pressure injected CO2 can displace oil efficiently in the zones that it invades.
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TABLE 7.6 U.S. Oil Resources and Reserves
Barrels (billion)
Estimated Cost Range ($/bbl)
Time Period for Significant Recovery
Oil Reserves (2007 annual U.S. production: 2.5 billion bbla)
Conventional light oil proved reservesb
22
10–20
<2020
Natural gas liquid proved reservesc
8
<2020
Technically Recoverable Resources
Light oil EORd
90
20–45
<2020
Heavy oil EORb
20
25–60
<2020
Residual zone EORc
20
60–130
2020–2035
Undiscovered conventional (onshore)b
43
40–60
2010–2035
Undiscovered conventional (offshore)b
76
75–95
2020–2035
Undiscovered EOR (onshore)b
22
50–75
>2035
Undiscovered EOR (offshore)b
38
105–145
>2035
Reserve growth (conventional recovery)b
71
10–20
<2020
Reserve growth (EOR)b
40
20–45
2020–2035
Tar sandsb
10
40–95
>2035
Oil shalese
500
40–95
>2035
aBritish Petroleum, 2008.
bDOE, 2006a.
cBritish Petroleum, 2008.
dDOE, 2006b.
eBartis et al., 2005.
An extensive infrastructure of pipelines in west Texas delivers CO2 to numerous oil fields. Much of that CO2 is transported by pipeline from natural CO2 sources in Colorado and New Mexico, though there are also significant EOR projects in west Texas, Wyoming, and Colorado that make use of CO2 separated from natural gas (instead of venting it to the atmosphere). The pipeline infrastructure demonstrates CO2 transport technology that would be needed to support large-scale geologic storage of CO2. These projects also allow assessment of whether injected CO2 has been retained in the subsurface (Klusman, 2003). For example, measurements of CO2 seepage at the surface above the Rangely Field in Colorado indicate that the rate of CO2 escape from the storage formation is very low (less than 170 tonnes per year over an area of 72 km2). Currently, CO2 injection for EOR is limited mainly by the availability of CO2 at a reasonable cost. If CO2 were more widely available in the future at a reasonable distance from existing oil fields as a result of limits on CO2 emissions, more widespread use of CO2 EOR could be
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anticipated. (See the section titled “Geologic Storage of CO2” later in this chapter and the section titled “Oil and Gas Reservoirs” in Annex 7.A for additional discussion of the potential for CO2 EOR to contribute to geologic storage of CO2.)
Heavy oils are difficult to displace; hence, typical primary recovery of oil from such reservoirs is much lower than that of lighter oils. Heavy oil is typically recovered by injecting steam, which warms the oil and reduces its viscosity so that it can flow more easily into production wells. Steam for injection is typically generated by burning a portion of the oil produced or by burning natural gas in areas where air-quality restrictions limit use of the crude oil as a fuel. This technology is now relatively mature and has been applied widely in heavy-oil fields in California, for example. Dissolving CO2 in heavy oil also reduces its viscosity, but the use of CO2 to recover heavy oil has not been tested in field projects.
Residual zone EOR refers to the possibility that some of the oil that is found in the transition zone between water and oil at the base of a reservoir can also be recovered by CO2 injection. This process is less well proven and likely more expensive than CO2 injection in zones that have less water and more oil present.
The estimates of undiscovered conventional and EOR resources in Table 7.6 are based on assessments by the U.S. Geological Survey (USGS) and the U.S. Minerals Management Service (MMS). The estimates shown for technically recoverable resources are 33 percent of those amounts for conventional recovery and an additional 17 percent for EOR. Reserve growth refers to the observation that the amount of oil listed as proved reserves often increases over time; information obtained through development drilling in the field is used to refine initial estimates of oil in place.
There is currently no significant production of oil from tar sands in the United States, as the U.S. tar sand resource is modest. There is a much larger resource of tar sands in Canada, however, and it has shown significant growth in production. The technically recoverable Canadian resource is estimated at 173 billion barrels (RAND, 2008), and the EIA projects production rates of 2.1–3.6 million barrels per day in 2020 and 4 million barrels per day in 2030, depending on oil price.
The largest oil resource listed in Table 7.6 is from oil shales, but it is among the most uncertain. The estimated overall resource is very large (1.5–1.8 trillion barrels); one source has estimated that as much as a third of it could eventually be recovered by some combination of mining followed by surface retorting or in situ retorting (Bartis et al., 2005). There is currently no production of oil from shale in the United States, though a new process for in situ retorting based on electric
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heating of the shale in the subsurface is being tested (Shell, 2006). Environmental impacts associated with mining, limitations on availability of water for processing, and potential demand for electricity to be used for in situ retorting must be assessed before better-constrained estimates of recoverable quantities of oil from shales can be assembled. Also, current cost estimates for shale oil recovery are not well defined.
In the absence of CO2 capture and storage, production of oil either by enhanced oil recovery methods or by conversion from tar sands or oil shales emits more CO2 than does conventional oil production. This is shown in Figure 7.1, which provides estimates of the potential emissions that result from production and use of fuels from various primary fossil-fuel resources (Farrell and Brandt, 2006).6 The fuels all have about the same CO2 emissions when they are burned, but the energy requirements to recover and upgrade the hydrocarbons vary significantly. As an example, fuels from tar sands may ultimately emit about 40 percent more CO2 than do fuels from conventional oil,7 though the ranges of estimated emissions indicate that there are significant uncertainties in the values reported. These emissions can in principle be mitigated by large-scale carbon capture and storage (CCS), as noted above, or by the use of low-carbon technologies for process heat and hydrogen production. In addition, both surface mining and in situ production of tar sands disrupt large land areas, as would surface mining of oil shales, and the amounts of water required to process the fuels will also be a constraint in some areas. Thus, there are significant environmental issues associated with the recovery and processing of some of the unconventional hydrocarbon resources.
Although the U.S. oil resource base is large, future domestic production will depend on two factors. One is the decline in production from existing fields. The decline rate varies from field to field, but it is everywhere significant. For example, the EIA assumes that currently producing fields decline at the rate of 20 percent per year. New fields are assumed to peak after 2 to 4 years, stabilize for a period, and then decline at the 20 percent rate (EIA, 2008b). While the National Petro-
6
For a discussion of emissions associated with various fuel conversions, see Chapter 5.
7
Emissions of CO2 result from the use of significant quantities of natural gas to provide process heat for separating the hydrocarbons from the sand and for making the hydrogen needed to upgrade the oils. These emissions could be reduced significantly in the future if nonfossil sources of electricity and process heat, such as nuclear, were used in the recovery and conversion processes.
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FIGURE 7.A.6 Component costs for the storage systems listed in Figure 7.14.
Source: Dooley et al., 2006.
testing of all three settings have been done. Use of basalt formations and organic-rich shales has been proposed, but neither has been tested in the field (Dooley et al., 2006; NETL, 2007b). And while sedimentary rocks that might be suitable for CO2 injection are widespread, not all locations would be appropriate. Storage in saline formations and coal beds will also require seal formations above the storage formation that prevent vertical migration of the CO2 to the surface. Appropriate sites will have to be selected that have sufficient pore space available and that have rock properties that allow the CO2 to be injected at a reasonable rate.
Figure 7.A.6 shows estimates of the cost components of CCS for various sources, sinks, and geographic distances between them. Note that there is no single homogeneous “CCS technology” or situation; economic viability will depend on specific source and sink characteristics. For situations in which the CO2 is already separated (natural gas processing, H2 production, or ammonia production, for example), the incremental separation cost is zero. About 6 percent of U.S.
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emissions of CO2 come from high-purity sources of this sort (Dooley et al., 2006), which provides opportunities for testing geologic storage at significant scale without requiring additional separations or constructing new power plants. In the limited instances where those sources are relatively close to locations at which EOR might be undertaken, the net cost of storage could be negative, as the revenue from oil sales would likely exceed the cost of storage. At coal-fired power plants, the largest sources in numbers and total emissions of CO2, the cost of CO2 capture typically exceeds the estimated costs of compression, transportation, and injection into the subsurface.
Dooley et al. (2006) estimated CO2 capture costs ranging from zero (for plants that already separate a high-purity CO2 stream) to $57 per tonne CO2 (for a low-purity natural gas-fired combined-cycle power plant), and compression costs of $6–12 per tonne CO2. Transportation costs were estimated to range from $0.2 to $10 per tonne CO2, with the low-cost end of the range being for large-volume pipelines. Geologic storage costs are also likely to vary with the specific application. Dooley et al. estimated costs of minus $18 to plus $12 per tonne CO2 for saline aquifer, EOR, and enhanced coal bed methane-injection projects, with the negative- and low-cost estimates applicable when cost recovery through sale of hydrocarbons is possible. Costs that are roughly consistent with these numbers are reported in the IPCC Special Report on Carbon Capture and Storage (IPCC, 2002), when corrections to translate 2002 costs to 2006 are made.
The forgoing estimates of potential costs of storage are “bottom-up,” based largely on engineering estimates of expenses for transport, land purchase, drilling and sequestering, and capping wells. However, quantified factors based on engineering analysis may represent a lower bound on future costs. Uncertainty in the regulatory environment created by public resistance to CCS could result in costly delays in implementation at the project level, both during the demonstration phase over the next decade and even when CCS has attained full commercial-scale operation (Palmgren et al., 2004; Wilson et al., 2007; IRGC, 2008). Extra costs could be incurred at a given project site because of interruption of operations even at a different site, given that the technologies, monitoring, and regulation of storage are likely to be closely related across sites. Costs usually not taken into account also result from the likely need to secure storage rights a very large amount of belowground space for the lifetime of a facility (Socolow, 2005).
One feature of CCS that improves the odds of deployment evolving without major disruption is that many of the early CCS projects will be EOR projects. They would likely be located where the general population is already familiar with
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and tends to be positively disposed toward the oil and gas industry, and where there will be revenue streams of benefit to all royalty holders, including local and state governments (Anderson and Newell, 2004).
Risks associated with storage are often handled uneventfully in the normal course of events, with smooth and reliable licensing, operation, and monitoring that make for minimal regulatory delays. Carbon dioxide is routinely transported long distances, injected underground, and stored at present without much attention from either the public or policy makers. Similarly, natural gas and chemical storage are longtime facts of life (Reiner and Herzog, 2004), and serious accidents and leaks do not threaten operations, at least not on an industry-wide basis. But counterexamples, from Bhopal to Three-Mile Island to Yucca Mountain, are easily cited as well. In short, public reaction is unpredictable.
Oil and Gas Reservoirs
Most of the experience in CO2 injection into the subsurface comes from oil fields. High-pressure CO2 has been used for more than three decades for enhanced oil recovery (EOR), with the largest operations being in west Texas. Most of the CO2 injected for EOR has come from natural underground CO2 sources rather than anthropogenic sources, but some has been obtained from natural gas processing operations that remove CO2 from the gas prior to sale.
Oil and gas reservoirs trap buoyant fluids that would otherwise escape to the surface, and hence the formations above the porous zones that contain the oil and gas should prevent vertical migration of CO2 as well. While similar principles apply to injection of CO2 into gas reservoirs, experience there is much more limited because the combination of gas prices and CO2 costs has not favored enhanced gas recovery using CO2. A test is currently under way, however, in the K12B gas reservoir in the Netherlands (IPCC, 2002).
In an oil- or gas-production operation, two key measures are critical: the amount of recoverable hydrocarbons, and the production rate per well. The analogy for CO2 storage or disposal is to determine the total mass of CO2 that can be injected into a target formation and the injection rate per well.
As an example, the Weyburn Field in Saskatchewan is injecting 95 million cubic feet per day of anthropogenic CO2 (from the Great Plains Synfuels Plant in North Dakota) into 37 wells (IPCC, 2005). This field has a total hydrocarbon volume of 1.4 billion barrels, of which 330 million had been produced—about 23 percent of the original oil in place—at the time CO2 injection commenced. It is
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anticipated that about 20 million tonnes of CO2 will be injected and become permanently stored some 1400 m (4600 ft) underground over the 25-year lifetime of the EOR project (expected to produce an additional 130 million barrels of oil).
The Great Plains Synfuels Plant, constructed in 1984, produces a variety of feedstocks from coal for products that include fertilizer, pesticides, gasoline, resins, krypton and xenon gases, and liquid hydrogen, in addition to the carbon dioxide that is sold to the Weyburn Field for EOR. Over its lifetime, the Weyburn Field project will inject about one-third of the concurrent CO2 output of a 1000 MW coal plant.
Other currently active EOR projects using CO2 from natural underground sources have original-oil-in-place volumes ranging from about 40 million to 2 billion barrels and CO2 injection rates of 50–100 million cubic feet per day (3000–5000 tonnes CO2 per day). Typically, existing production wells can be transformed into injectors at less than the cost of drilling the new wells that would be required for sequestration in a saline aquifer. Also, EOR projects offset the injection costs with revenue from produced oil.
Using CO2 for EOR has obvious benefits, but project locations, injection rates, and service lives may not be sufficient for EOR, by itself, to accommodate the lion’s share of CO2 emissions from power plants. Although there is far more capacity for storing CO2 in saline aquifers, wherever storage through EOR is possible it should prove very attractive, given the potential for cost recovery and the use of at least a portion of an existing infrastructure within the oil fields.
Saline Aquifers
Saline-aquifer storage is expected to be the workhorse storage option in the United States (Dooley, 2006). Saline-aquifer storage has also been tested in the Sleipner Field of offshore Norway at a scale similar to that of the Great Plains example (IPCC, 2005). The Sleipner Field produces natural gas that contains CO2, which is separated from the natural gas and reinjected into the very large Utsira Formation, which is sandstone. Because that formation has high permeability (fluids flow relatively easily through the rock), only one injection well is required to handle about 1 million tonnes per year of CO2 (2700 tonnes per day). Seismic evidence collected periodically indicates that the CO2 has been contained in the Utsira Formation. While there is enough experience to date to indicate that CO2 injection into formations that contain salt water can be undertaken, the combination of technologies required to store CO2 from a large coal-fired power plant has not yet been demonstrated at sufficient scale.
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Coal Beds
Coal-bed storage is the least well understood of the three main storage options. The mechanism depends on the fact that CO2 adsorbs onto coal surfaces, and it does so more strongly than does methane. In 2005 coal-bed methane production was 1.7 Tcf, about 9 percent of U.S. natural gas production (http://tonto.eia.doe.gov/dnav/ng/ng_enr_cbm_a_EPG0_r52_Bcf_a.htm). In a typical coal-bed methane project, water is removed to reduce pressure, and the methane released from the coal at the lower pressure flows through fractures in the coal to producing wells. CO2 injected into a fractured coal bed replaces adsorbed methane, which creates the possibility of enhanced coal-bed methane production using CO2. While some coals can take up significant quantities of CO2, flow through the coal becomes more difficult as the CO2 adsorbs. Injection of CO2 into a coal bed was tested at the Allison Unit in New Mexico, where significant permeability reductions were observed (IPCC, 2005). More testing will be required at various scales before significant storage in coal beds is likely to occur.
Retention of CO2 in the Subsurface
Subsurface formations that are appropriate for CO2 storage will have rock layers above the storage zone that do not permit vertical flow. Those seal rocks, often shales or evaporites, will be needed to isolate the injected CO2 from the near-surface region for an extended period during which several physical mechanisms act to immobilize the CO2. When CO2 dissolves in brine, for example, the resulting mixture is slightly denser than brine alone, and hence the driving force for upward migration of the CO2 disappears, and the flow of the CO2-laden brine away from the CO2 zone helps dissolve the CO2 more quickly than it would by diffusion alone. When brine invades areas formerly occupied by CO2 as it dissolves, trapping of the CO2 as isolated bubbles occurs. These bubbles cannot move under the small pressure gradients present. Dissolution and trapping happen on timescales that range from centuries to a few thousand years, depending on the permeability of the formation (Riaz et al., 2006; Ide et al., 2007). On longer timescales (multiple thousands of years) chemical reactions can convert some of the CO2 to solid materials, depending on the composition of the brine and the minerals present in the rock.
Safe operations of storage sites will require that the amount of CO2 allowed to escape from the deep storage zone to the near-surface environment be very small. Oil and gas reservoirs provide an example of the kind of storage settings
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that retain buoyant fluids for geologic time periods. Nevertheless, it is possible that some storage sites might leak, and hence the quantitative impact of leakage has been assessed. Based on IPCC emission scenarios, Hepple and Benson (2005) argue that overall rates of leakage less than 0.01 to 0.1 percent annually of the total amount stored would be sufficient to allow CCS to contribute effectively to the stabilization of CO2 concentration in the atmosphere, depending on the target. If leakage occurs, it is more likely to happen relatively early in the life of a storage site, when pressures are highest around an injection well. Wells are the most likely leak path, but well leakage is readily detected and can be repaired.
Careful attention to leakage hazards will be required in any CCS project. At low concentrations in air, CO2 is not dangerous. It is a normal component of air, and large power plants currently emit millions of tonnes per year directly to the atmosphere. At high concentrations, however, it is an asphyxiant and is toxic. A concentration of 4 percent CO2 is immediately dangerous to health, and the NIOSH and OSHA exposure limits (NIOSH, 1996) are 5000 ppm (0.5 percent). Because CO2 is denser than air is, designing and monitoring CO2 pipelines and wells to make sure that leaking CO2 does not collect in low-lying areas is essential. Storage security generally increases with time after injection ceases (IPCC, 2005), as the highest subsurface pressures relax, as CO2 dissolves in brine, and as trapping of CO2 occurs. Monitoring schemes such as those used at Sleipner and other field tests (Chadwick et al., 2008; Daley et al., 2008) can be used to determine whether the CO2 is remaining isolated from the surface over time.
Nontechnical Issues with CCS
Whichever of the three main options are used, significant regulatory issues will have to be addressed if geologic storage is to be undertaken on a large scale. These issues include long-term ownership of the CO2, liability exposures over time, requirements for the monitoring of storage sites, and regulations for safe operation. Figure 7.A.7 outlines the decision points associated with the life cycle of a storage facility. For a detailed discussion of the many issues that arise in site selection and project design and implementation, see Chapter 5 of IPCC (2005).
Site screening will include matching of potential CO2 sources and sinks, with appropriate attention to the feasibility of separating the CO2 and transporting it to the storage location. Similarly, attention must be given to understanding the subsurface characteristics: in particular, the potential storage capacity, the permeability of the formation (which will control injection rates and pressures), the
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FIGURE 7.A.7 Key steps in the implementation of a large-scale CO2 storage project.
Source: J. Friedmann, presentation at the AEF Committee’s fossil fuels workshop, 2008.
existence of appropriate barriers to vertical flow, and the absence of likely leak paths. Once potentially appropriate source/sink combinations have been identified, additional effort—including more detailed study of the properties of the geologic formation, the drilling of one or more test wells, and analysis of rock samples—will be required to refine the characterization of the subsurface. In that way, predictions of flow behavior and the long-term fate of injected CO2 can be made. These predictions will be part of a permitting process involving some combination of local, state, and federal regulatory agencies, depending on the specific location (Wilson et al., 2007).
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As part of this process, an appropriate level of project-performance monitoring will need to take place. A number of geophysical techniques are available for monitoring the movement of the CO2 in the subsurface and the vicinity of the injection project (see Table 5.4 of IPCC [2005]). Which techniques are appropriate will depend on the geologic setting and on the project’s stage. During the injection phase, monitoring activities will likely be more extensive in the initial years to ensure that the injected CO2 is entering the intended formation and that surface leaks in the injection area do not occur (wells and the associated pipes and fittings are the most likely sources of leaks, but they can also be repaired most easily). Time-lapse seismic methods have been demonstrated for detection of the subsurface movement of the CO2, and electromagnetic and gravity surveys may also be used in some settings. After injection of CO2 ceases, there will still be a period in which gravitational forces cause the buoyant CO2 to move in the subsurface, but the rate of movement will decline with time; hence the need for frequent monitoring activities will also decline.
Many issues associated with the development of appropriate regulatory processes remain to be resolved. In particular, what entity would bear long-term liability after injection has ceased? Testing of geologic storage of CO2 is allowed under existing regulatory structures, but these regulations must be further developed in order to embrace large-scale implementation of CO2 injection for the purpose of avoiding emissions of CO2 to the atmosphere (Wilson et al., 2007). That development process is now in the beginning stages. In July 2008, the U.S. Environmental Protection Agency issued proposed rules for regulation of underground injection of CO2 under the Safe Drinking Water Control Act (www.epa.gov/safewater/uic/wells_sequestration.html#regdevelopment). The rules would create a new class of injection well for CO2 as part of the Underground Injection Control program. They would also include requirements for storage-site characterization, injection-well design and testing, monitoring of project performance, and demonstration of financial responsibility.
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