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Kaarstad, 2002

a No further breakdown figures are available. Subset of a larger system of capital and operating costs for several processes, mostly natural gas and condensate processing.

5.9.3 Cost estimates for CO2 geological storage

This section reviews storage costs for options without benefits from enhanced oil or gas production. It describes the detailed cost estimates for different storage options.

and gas fields at the same depths have storage costs of 3.8-8.1 US$/tCO2 stored (most likely value is 6.0 US$/tCO2 stored). The costs depend on the depth of the reservoir and reuse of platforms. Disused fields may benefit from reduced exploration and monitoring costs.

5.9.3.1 Saline formations

The comprehensive review by Allinson et al., (2003), covering storage costs for more than 50 sites aroundAustralia, illustrates the variability that might occur across a range of sites at the national or regional scale. Onshore costs for 20 sites have a median cost of 0.5 US$/tCO2 stored, with a range of 0.2-5.1 US$/tCO2 stored. The 37 offshore sites have a median value of 3.4 US$/tCO2 stored and a range of 0.5-30.2 US$/tCO2 stored. This work includes sensitivity studies that use Monte Carlo analyses of estimated costs to changes in input parameters. The main determinants of storage costs are reservoir and injection characteristics such as permeability, thickness and reservoir depth, that affect injection rate and well costs rather than option type (such as saline formation or depleted field).

Bock et al. (2003) have made detailed cost estimates on a series of cases for storage in onshore saline formations in the United States. Their assumptions on geological characteristics are based on a statistical review of more than 20 different formations. These formations represent wide ranges in depth (700-1800 m), thickness, permeability, injection rate and well numbers. The base-case estimate for average characteristics has a storage cost of 0.5 US$/tCO2 stored. High- and low-cost cases representing a range of formations and input parameters are 0.4-4.5 US$/tCO2 stored. This illustrates the variability resulting from input parameters.

Onshore storage costs for saline formations in Europe for depths of 1000-3000 m are 1.9-6.2 US$/tCO2, with a most likely value of 2.8 US$/tCO2 stored (Hendriks et al., 2002). This study also presents estimated costs for offshore storage over the same depth range. These estimates cover reuse of existing oil and gas platforms (Hendriks et al., 2002). The range is 4.7-12.0 US$/tCO2 stored, showing that offshore costs are higher than onshore costs.

5.9.3.2 Disused oil and gas reservoirs

It has been shown that storage costs in disused oil and gas fields in North America and Europe are comparable to those for saline formations (Hendriks et al., 2002; Bock et al., 2003). Bock et al. (2003) present costs for representative oil and gas reservoirs in the Permian Basin (west Texas, USA). For disused gas fields, the base-case estimate has a storage cost of 2.4 US$/tCO2 stored, with low and high cost cases of 0.5 and 12.2 US$/tCO2 stored. For depleted oil fields, the base-case cost estimate is 1.3 US$/tCO2 stored, with low- and highcost cases of 0.5 and 4.0 US$/tCO2 stored. Some reduction in these costs may be possible by reusing existing wells in these fields, but remediation of abandoned wells would increase the costs if required.

In Europe, storage costs for onshore disused oil and gas fields at depths of 1000-3000 m are 1.2-3.8 US$/tCO2 stored. The most likely value is 1.7 US$/tCO2 stored. Offshore oil

5.9.3.3 Representative storage costs

The different studies for saline formations and disused oil and gas fields show a very wide range of costs, 0.2-30.0 US$/tCO2 stored, because of the site-specific nature of the costs. This reflects the wide range of geological parameters that occur in any region or country. In effect, there will be multiple sites in any geographic area with a cost curve, providing increasing storage capacity with increasing cost.

The extensive Australian data set indicates that storage costs are less than 5.1 US$/tCO2 stored for all the onshore sites and more than half the offshore sites. Studies for USA and Europe also show that storage costs are generally less than 8 US$/tCO2, except for high-cost cases for offshore sites in Europe and depleted gas fields in the United States. A recent study suggests that 90% of European storage capacity could be used for costs less that 2 US$/tCO2 (Wildenborg et al., 2005b).

Assessment of these cost estimates indicates that there is significant potential for storage at costs in the range of 0.5-8 US$/tCO2 stored, estimates that are based on the median, base case or most likely values presented for the different studies (Table 5.9). These exclude monitoring costs, well remediation and longer term costs.

5.9.3.4 Investment costs for storage projects

Some information is available on the capital and operating costs of industry capture and storage projects (Table 5.10). At Sleipner, the incremental capital cost for the storage component comprising a horizontal well to inject 1 MtCO2 yr-1 was US$ 15 million (Torp and Brown, 2005). Note that at Sleipner, CO2 had to be removed from the natural gas to ready it for sale on the open market. The decision to store the captured CO2 was at least in part driven by a 40 US$/tCO2 tax on offshore CO2 emissions. Details of the energy penalty and levelized costs are not available. At the planned Snohvit project, the estimated capital costs for storage are US$ 48 million for injection of 0.7 MtCO2 yr-1 (Kaarstad, 2002). This data set is limited and additional data on the actual costs of industry projects is needed.

5.9.4 Cost estimates for storage with enhanced oil and gas recovery

The costs of CO2 geological storage may be offset by additional revenues for production of oil or gas, where CO2 injection and storage is combined with enhanced oil or gas recovery or ECBM. At present, in commercial EOR and ECBM projects that use CO2 injection, the CO2 is purchased for the project and is a significant proportion of operating costs. The economic benefits from enhanced production make EOR and ECBM potential early options for CO2 geological storage.

5.9.4.1 Enhanced oil recovery

The costs of onshore CO2-flooding EOR projects in North America are well documented (Klins, 1984; Jarrell et al., 2002). Carbon dioxide EOR projects are business ventures to increase oil recovery. Although CO2 is injected and stored, this is not the primary driver and EOR projects are not optimized for CO2 storage.

The commercial basis of conventional CO2-EOR operations is that the revenues from incremental oil compensate for the additional costs incurred (including purchase of CO2) and provide a return on the investment. The costs differ from project to project. The capital investment components are compressors, separation equipment and H2S removal, well drilling and well conversions and completions. New wells are not required for some projects. Operating costs are the CO2 purchase price, fuel costs and field operating costs.

In Texas, the cost of CO2 purchase was 55-75% of the total cost for a number of EOR fields (averaging 68% of total costs) and is a major investment uncertainty for EOR. Tax and fiscal incentives, government regulations and oil and gas prices are the other main investment uncertainties (e.g., Jarrell et al., 2002).

The CO2 price is usually indexed to oil prices, with an indicative price of 11.7 US$/tCO2 (0.62 US$/Mscf) at a West Texas Intermediate oil price of 18 US$ per barrel, 16.3 US$/ tCO2 at 25 US$ per barrel of oil and 32.7 US$/tCO2 at 50 US$ per barrel of oil (Jarrell et al., 2002). The CO2 purchase price indicates the scale of benefit for EOR to offset CO2 storage costs.

5.9.4.2 Cost of CO2 storage with enhanced oil recovery Recent studies have estimated the cost of CO2 storage in EOR sites (Bock et al., 2003; Hendriks et al., 2002). Estimates of CO2 storage costs for onshore EOR options in North America have been made by Bock et al. (2003). Estimates for a 2-MtCO2 yr-1 storage scenario are based on assumptions and parameters from existing EOR operations and industry cost data. These include estimates of the effectiveness of CO2-EOR, in terms of CO2 injected for each additional barrel of oil. The methodology for these estimates of storage costs is to calculate the breakeven CO2 price (0.3 tCO2).

Experience from field operations across North America provides information about how much of the injected CO2 remains in the oil reservoir during EOR. An average of 170 standard m3 CO2 of new CO2 is required for each barrel of enhanced oil production, with a range of 85 (0.15 tCO2) to 227 (0.4 tCO2) standard m3 (Bock et al, 2003). Typically, produced CO2 is separated from the oil and reinjected back underground, which reduces the cost of CO2 purchases.

The base case for a representative reservoir at a depth of 1219 m, based on average EOR parameters in the United States with an oil price of 15 US$ per barrel, has a net storage cost of -14.8 US$/tCO2 stored. Negative costs indicate the amount of cost reduction that a particular storage option offers to the overall capture and storage system. Low- and high-cost cases representing a range of CO2 effectiveness, depth, transport distance and oil price are -92.0 and +66.7 US$/tCO2 stored. The low-cost case assumes favourable assumptions for all parameters (effectiveness, reservoir depth, productivity) and a 20 US$ per barrel oil price. Higher oil prices, such as the 50 US$ per barrel prices of 2005, will considerably change the economics of CO2-EOR projects. No published studies are available for these higher oil prices.

Other estimates for onshore EOR storage costs all show potential at negative net costs. These include a range of -10.5 to +10.5 US$/tCO2 stored for European sites (Hendriks et al., 2002). These studies show that use of CO2 enhanced oil recovery for CO2 storage can be a lower cost option than saline formations and disused oil and gas fields.

At present, there are no commercial offshore EOR operations and limited information is available on CO2 storage costs for EOR options in offshore settings. Indicative storage cost estimates for offshore EOR are presented by Hendriks et al. (2002). Their range is -10.5 to +21.0 US$/tCO2 stored. For the North Sea Forties Field, it has been shown that CO2-flooding EOR is technically attractive and could increase oil recovery, although at present it is not economically attractive as a stand-alone EOR project (Espie et al., 2003). Impediments are the large capital requirement for adapting facilities, wells and flowlines, as well as tax costs and CO2 supply. It is noted that the economics will change with additional value for storage of

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