CCS Carbon Chain

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The carbon chain from fossil fuel or biomass from its source through the process to carbon capture and sequestration (CCS) is shown in Fig. 2.15. We have already considered the first two steps (boxes) in the figure for power generation.

Useful Products (Electricity, Fuels, Chemicals, Hydrogen)

- Post-combustion . Pipeline

- Pre-combustion _ Tanker

- Oxyfuel combustion

Depl. oil'gas fields Sal me reservoirs

Unmineable coal seams Ocean

Mineralization

Fig. 2.15 Full carbon chain from fossil fuel input to carbon capture and sequestration

The last two steps in the carbon chain, pipeline transport and injection, will now be considered, as will their impact on COE estimated. These costs are already included in Tables 2.4 and 2.7; this section develops and discusses their cost basis. To estimate cost impact, a model of a typical CCS project is needed. Oil and gas reservoirs and enhanced oil recovery (EOR) are often discussed for geologic storage of CO2. These storage sites-of-opportunity may play a role initially; but they have limited long-term potential because of the scale of CO2 CCS that will be needed to make a major difference in managing CO2 from coal-based power generation. Today, EOR uses 35-40 million tonnes of CO2 per year which could be supplied by a few early CCS projects (see Table 2.1). Larger-volume, long-term storage for the U.S. will largely be in deep saline aquifers. These geologic formations underlie large portions of the U.S., particularly those areas that today have a lot of coal-based power generation and where additional coal-based generating capacity could be expected to be added as shown in Fig. 2.16. In fact, there is a high degree of coincidence between potential coal deposits, coal-based power generating sites, and potential geologic CO2 storage sites.

The primary mode of CO2 transport for sequestration operations will be via pipelines. There are over 2,500 km of CO2 pipeline in the U.S. today, with a capacity in excess of 40 million tonnes CO2/year. These pipelines were developed to support EOR operations, primarily in west Texas and Wyoming. In these pipelines, CO2 is transported as a dense, single-phase fluid at ambient temperature and supercritical pressure. To avoid corrosion and hydrate formation, water levels are typically kept below 50 ppm. The pipeline technology is mature, and most costs can be estimated. The main unknowns are the costs of permitting, acquisition of right-of-way, and additional costs associated with local terrain (rivers, roads, high density inhabited areas).

H Saline Aquifers Hf Coalbeds

Total Coal-Fired Capacity = 330 GW

Fig. 2.16 Location of deep saline aquifers, oil and gas fields, coal beds and coal based power plants for U.S. [10]

H Saline Aquifers Hf Coalbeds

Total Coal-Fired Capacity = 330 GW

Fig. 2.16 Location of deep saline aquifers, oil and gas fields, coal beds and coal based power plants for U.S. [10]

However, rather than having long-distance CO2 pipelines running across the country, a typical CCS power plant project could be expected to look something like that illustrated in Fig. 2.17. It is expected that sufficient capacity would be accessible within about a 100 km radius for a good location. Location is important, but once sited the CO2 storage requirement for the lifetime of the power plant, which would be of order a billion barrels of liquid CO2 should be within that area. The total reservoir CO2 capacity must be sufficient so that by accessing different portions of the reservoir over the lifetime of the plant all the CO2 captured can be safely stored.

The Transport and Storage (T&S) costs used here were updated to 2007 using recent reviews by McCollum and Ogden and by Tarka [36, 37]. Pipelining costs were updated using the Handy-Whitman Index of Public Utility Costs for Gas Transmission Line Pipe and Steel Distribution Pipe and operating costs updated using U.S. Bureau of Standards Producer Price Indices for the Oil and Gas Industry [37]. Capital costs were levelized over a 20-year period and include a 30% process contingency and a 20% project contingency. Monitoring costs are included and used the IEA Greenhouse Gas R&D Program [38]. This includes operational monitoring costs tracking the plume for 30 years and closure monitoring costs for the following 50 years. An operational fund is capitalized to cover the 80 year monitoring cycle. The storage site is chosen to be representative of a typical saline aquifer at a depth of 4,055 feet depth and 22 millidarcies permeability and 1,220-psi down-hole pressure. A $5 million initial site assessment was assumed. Costs were estimated from this basis.

Refinery Operations Planning
A Planning for a CCS-enabled power plant must include a robust CO2 storage plan for all phases of the plant's operations over its entire half-century operational lifetime.

Fig. 2.17 Conceptual model of a typical CCS project (Courtesy Battelle, GTSP report)

The transportation costs dominate the CO2 T&S costs and are highly non-linear with the amount of CO2 transported. The economies-of-scale make transportation costs for large CCS projects much less expensive. For example, for 1 million tonnes of CO2 per year (2,500 tonnes/day) the estimated transport cost is about $8.00 per tonne per 100 km; at 3.5 million tonnes CO2 the estimated transport cost is about $5.00 and at 7 million tonnes of CO2 per year the cost is about $3.00 per tonne per 100 km. These are typical values, but costs are dependent on pipeline costs which can be highly variable from project to project due to both physical (e.g., terrain the pipeline must traverse) and political considerations. In addition, there are a number of other issues that can have a significant impact on potential CCS projects. These include state and federal laws and regulations, and political, public, and environmental concerns.

For a 1 GWe coal-fired power plant, pipeline capacity of about 6-7 million tonnes of CO2/year would be needed. This would result in a transport cost of about $3.00 per tonne of CO2 per 100 km.

The major cost for injection and storage is associated with drilling the wells and the associated flow lines and connectors required for injection. However, capital requirements associated with storage are typically less than 20% of the capital requirements associated with transport. On the other hand, the operating and maintenance costs associated with storage are 30-40% of the O&M costs for transport. Other significant costs include site selection, characterization, and monitoring. In general, no additional pressurization of the CO2 is required for injection because of the high pressure in the pipeline and the pressure gain due to the gravity head of the CO2 in the wellbore. Monitoring costs are expected to be small, of order $0.1-$0.3 per tonne of CO2 [39].

Costs for injecting the CO2 into geologic formations will vary with formation type, its permeability, thickness, and other properties. For example, costs increase as reservoir depth increases and as reservoir permeability and injectivity decreases. Lower permeability requires drilling more wells for a given rate of CO2 injection. A range of typical injection costs has been reported as $0.5-$8 per tonne of CO2 [39]. For an average U.S. deep saline aquifer (1,000 m deep, 22 millidarcies permeability, and 160 m thick) the estimated storage cost is $1.60 per tonne of CO2 for 1 million tonnes/year (2,500 tonnes/day) storage rate and $0.50 per tonne CO2 for 3.5 million tonnes per year (10,000 tonnes/day) [37]. Although limited in scale, combining storage with EOR can help offset some of the capture and storage costs. EOR credits of up to $20 per tonne of CO2 may be obtained.

Representative projected costs, on a levelized basis per kWe-h, are shown in Table 2.8 for coal-based PC and IGCC power generation. The costs for transport and storage are significant, but both are small and represent a small, acceptable fraction of the total cost. Transport and storage costs include the cost of constructing pipelines and of drilling the injection wells, as well as the system operating costs. The numbers used were updated to 2007 using typical terrain and saline reservoir properties [36, 37]. The largest cost is in CO2 capture and compression (Table 2.8). For IGCC, the projected cost of CCS would increase the bus bar cost of electricity by about 40%, from 6.8 to about 9.40/kWe-h. IGCC with CCS vs. PC venting would represent about a 50% increase in the bus bar COE. This electricity

Table 2.8 Cost of CCS projected for PC and IGCC generation with CO2 capture

Technology

PC

IGCC

CCS Step

0/kWe-h

0/kWe-h

Capture

3.3

1.3

Compression

0.9

0.5

Transport

0.5

0.5

Injection

0.1

0.1

Totals

4.8

2.4

would be very low emissions electricity, including low CO2 emissions. Furthermore, it is economically competitive with electricity generated by wind power and by new nuclear power plants [1].

Comprehensive geological reviews suggest that for carefully selected storage sites, there are no irresolvable technical issues for CO2 injection and storage with respect to its efficacy and safety[10]. However, there are technical issues that require better understanding. We have 30 years of successful CO2 injection experience from which we have found no critical issues. The Sleipner Project in Norway [40] has been injecting 1 million tonnes/year of CO2 into the Utsira Saline Formation since 1996 using a single well bore. Weyburn in Canada [41] has injected 0.85 million tonnes/year of CO2 into the Midvale reservoir for EOR since 2000, and In Salah [42] has been injecting 1 million tonnes/year of CO2 into the water leg of the gas field for several years also. None of these projects have encountered any problems, and there is no sign of CO2 leakage.

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