Carbon Sequestration Technology and Costs

One of the most widely discussed means of reducing CO2 emissions is carbon capture and sequestration. The basic method is to capture CO2 and inject it into secure geologic formations or into the deep ocean for long-term storage. This method holds much promise, and in a 1997 report, the President’s Committee of Advisors on Science and Technology (PCAST) recommended that funding within DOE’s fossil-energy R&D program be reformulated, emphasizing new technologies such as carbon capture and sequestration (PCAST 1997, p. 5).

Two current projects are being studied to better understand the feasibility of this type of solution in the reduction of global CO2 emissions. These are the Weyburn project in Saskatchewan, Canada and the Sleipner project in the North Sea off the coast of Norway. The motivations behind these two projects differ.

The Weyburn oil field, located in southeastern Saskatchewan, was discovered in 1954, containing approximately 1.4 billion barrels of oil. As production rates declined in the field, CO2 flooding (injection of CO2 into the field to increase production) was used to recover an additional 130 million barrels of oil and permanently sequester approximately 15.4 million net tons of CO2 for a total of 19.8 million tons of CO2. CO2 is captured at the Great Plains Synfuels Plant in North Dakota (coal-fired power plant) and transported in a supercritical state (2,100 pounds per square inch (psi)) via 323-km pipeline to the Weyburn site. Approximately 2,756 tons of CO2 per day have been injected into the reservoir since September 22, 2000 (Brown et al. 2001).

The CO2 sequestered at the North Sea Sleipner gas fields is not the result of burning fossil fuels, but is an impurity that is removed to prepare the gas for market. Formerly, the CO2 was vented to the atmosphere. When Norway instituted a tax on offshore carbon emissions of U.S. $50 per tonne, it became economically viable to capture and sequester the separated CO2 (the tax was later lowered to $38 per tonne). By avoiding this tax on one million tonnes of CO2 annually (3 percent of Norway’s total CO2 emissions), Statoil was able to recover its investment of $80 million in two years (Adam 2001).

Since, 1996 Statoil has been injecting the separated CO2 into a sandstone layer, known as the Utsira formation, 800 to 1,000 meters below the seabed (IEA 2003). After separation, the CO2 must be compressed to a supercritical state and injected into the rocky reservoir.

A seismic survey done by the British Geological Survey (BGS) in 1999 showed that the CO2 injected into the reservoir is likely to remain in place. The potential for storage is large. One percent of this reservoir would hold three years’ emissions from all the power plants in Europe (Adam 2001). A BGS report indicated that the North Sea has the potential to hold all of the CO2 from European power stations for 800 years (800 billion tonnes) (IEA 2003). One concern is that the CO2 may begin to compress, rather than dissipate throughout the formation, making future injection more difficult (Adam 2001).

8.3.1. Separation and Capture

According to Herzog, all current commercial CO2 capture is based on chemical absorption of CO2 from flue gas using a monoethanolamine (MEA) solvent (Herzog 1999, p. 4). The MEA/CO2 solution is sent to a stripper where it is heated, and nearly pure CO2 is released and the MEA is recycled (Herzog 1999, p. 5). Herzog notes that the majority of costs associated with carbon sequestration are incurred in separation and capture.

8.3.2. Cost Estimates

David (2000) compares several different studies to estimate costs associated with CO2 separation and capture for three types of new (not retrofit) power plants: Integrated Gas Combined Cycle (IGCC), Pulverized Coal Combustion (PCC), and Gas Turbine Combined Cycle (GTCC). He adjusts all the studies to a common economic basis to compare costs across studies. The averages David computed across studies for each plant type are reported in Table 8-1. The energy penalty is the additional input energy required to separate and capture the CO2. Additional energy means additional CO2, so the relevant figure is not CO2 captured, but CO2 avoided.

Table 8-1: Average Costs Across Studies: IGCC, PCC, and GTCC (David 2000)a Plant Type Incremental Cost of

Capture per MWh

Average Cost per Ton of CO2 Avoided

Energy Penalty, Percent IGCC $17.2 $27 6.4 to 21.4 PCC $34.8 $52 15.9 to 34.1 GTCC $15.9 $51 9.8 to 16.1 a

Although not specified in David’s reports, this study’s calculations confirm that these figures are metric tons, or tonnes. Yearly operating hours = 6,570 hrs per year; capital charge rate = 15 percent per year; coal price at lower heating value (LHV) = $1.24 per MMBtu; natural gas price (LHV) = $2.93 per MMBtu (David 2000).

8.3.3. Transport and Injection

Storage of CO2 is feasible in many different locations, including ocean storage—both at intermediate depths (> 1,500 m) and deep lake injection (> 3,000 m)—depleted gas and oil reservoirs, deep saline aquifers, and unminable coal seams (Ormerod 2002, Davison 2001). Transportation methods are dependent on both the location of the CO2 source and the

location of the sequestration site. Transportation methods include pipeline, truck, and ocean tanker. Costs associated with transportation would also be highly dependent on the distance and method used, but average costs have been estimated.

Herzog (2004, p. 10) notes that the costs of transportation via pipeline can vary greatly, depending on factors such as terrain and population density. He estimates the costs

of pipeline transportation of CO2 for a 1,500 MW coal-fired power plant (equivalent to a flow rate of 10 million metric tonnes per year) to be $0.50 per metric tonne per 100 km. Lower flow rates could be as high as $2.00 to $3.50 per metric tonne CO2 per 100 km (Herzog 2004, Figure 5). These figures are more in line with those cited by the IEA Greenhouse Gas R&D Programme of approximately $1 to $3 per tonne CO2 for 100 km (Davison 2001). Herzog’s estimate of truck transportation of CO2 is $6.00 per metric tonne per 100 km. Table 8-2 estimates the costs of transporting CO2 from different plant types using the (low) estimates from Herzog (2004) for pipeline transport ($0.50 per metric tonne per 100 km) and (high) truck transport ($6.00 per metric tonne per 100 km). The estimates presented are based on the following assumptions:

• Energy penalties for plant types are equal to the averages from studies presented in David (2000), or 14.53 percent, 25.18 percent, and 13.05 percent for IGCC, PCC, and GTCC plants, respectively, though no energy penalty is included for the additional energy required to transport the CO2 by truck;

• Distance from plant to injection site of 500 km (David 2000 notes that all power plants in the United States are located within 500 km of possible sequestration sites); and

• Capture rates of 88.2 percent, 86.9 percent, and 88.0 percent for IGCC, PCC, and GTCC plants, respectively (David 2000).

Table 8-2: Ground Transportation Cost Estimates, by Plant Type, $ per MWh

Plant Type

Pipeline @

$0.50 Per Metric tonne-100 km

Truck Transport @ $6.00 per Metric tonne-100

km

IGCC 1.9 22.8

PCC 2.1 25.7

GTCC 0.9 11.0

The IEA Greenhouse Gas R&D Programme estimated the costs associated with ocean transport of CO2. Ormerod (2002) notes: “Comparable 0.5 m diameter pipelines … cost about $1.6 million per km. Such pipelines have the capacity for 18,000 [tones of CO2 per day]…. The cost of transporting CO2 for 500 km, by such a pipeline, would be around $12/t CO2….” (Ormerod 2002, p. 13). Ormerod also notes the significant advantages a larger diameter pipe would have, with a 1-m diameter pipe transporting four times as much per day, but costing less than four times the price of the 0.5-m pipe. The IEA Program estimates transportation by tanker would be around $2 per tonne of CO2, though added to this would be the costs associated with a CO2 holding tank at the port, the platform, and the vertical pipe, as well as operating expenses (Ormerod 2002, p.14).

Two basic options exist for CO2 sequestration, storage in the oceans and underground storage. Three main geological structures are available for permanent or semi-permanent CO2 sequestration: depleted oil or gas reservoirs, deep saline aquifers, and unminable coal beds. Each option offers different benefits. The IEA Greenhouse Gas R&D Program estimates that depleted oil and gas reservoirs could store 920 Gt (Gigatonnes) of CO2, deep saline aquifers 400 to 10,000 Gt, and unminable coal beds an additional 15 Gt.

Herzog (1999) estimates injection and storage costs for CO2 to be between $3 and $5.5 per tonne of CO2. Table 8-3 shows the additional costs injection and storage would impose on power generation, by plant type. As with transportation costs, the cost per MWh is highest for PCC plants and lowest for GTCC plants. These differences are due to the variations by plant type in CO2 produced per kWh of electricity generated. The IEA Greenhouse Gas R&D Program estimates that the cost of storage in depleted oil and gas reservoirs and deep saline formations to be $1 to $3 per tonne CO2 (Davison et al. 2001).

Table 8-3: Injection and Storage Cost Estimates, by Plant Type, $ per MWh

Plant Type

Injection & Storage @ $1.00 per tonne-CO2

Injection & Storage @ $5.50 per tonne-CO2

IGCC 0.8 4.2

PCC 0.9 4.7

GTCC 0.4 2.0

8.3.4. Summary of Carbon Mitigation Costs

For any power plant there are costs associated with producing the power. If CO2 emissions become costly, either through a tax on emissions or through costs associated with sequestration, these costs become part of the private cost of producing power. Alternatively, any revenue from the sale of captured CO2 would be subtracted from the costs. These costs have the form:

FX + CCapture + CTransport + CInjection – PSale + TCO2 = FX+CO2, Where:

FX is cost of power production at facility type X = {IGCC, PC, NGCC}) without sequestration and capture

CCapture is the cost of separation and capture/compression for CO2 CTransport is the cost of moving the captured CO2 to the sequestration site

CInjectionis the cost of inserting the captured CO2 into the sequestration site

PSale is the benefit received by the power company from the sale of its product TCO2 is any tax imposed on CO2 emissions.

There is an additional energy penalty involved for both transportation and injection that is not included in the energy penalty for separation and capture.

Using this formulation, Table 8-4 summarizes the cost components of the full cycle of carbon sequestration, including capture, transport, and injection and storage. The transport costs assume a 100-km pipeline as an average across plants. The capture costs are the largest component, injection, and storage the smallest, and transport the most variable. Coal plants would face the greatest expense, although IGCC technology is better adapted to capture carbon than is pulverized coal, and gas the least.

Table 8-4: Summary of Components of Carbon Sequestration Cost, $ per MWh

Plant Type Capture Transport Injection and Storage Total

IGCC 17 2 to 23 1 to 4 20 to 44

PCC 34 2 to 26 1 to 5 34 to 65

GTCC 16 1 to 11 .5 to 2 17 to 29