This paper investigates ways in which CO2 storage in low-permeability formations might be made viable and how such formations might compete with more distant formations with higher permeability. Hypothetical, but realistic cases are postulated to examine the effect of reservoir engineering and economic sensitivities. The cases comparea large CO2 source with nearby abundant low-permeability pore space (0.1–10md) withthe same source with storage in a remote high permeability (100md) site. Based on reservoir engineering and economic analyses, the paper quantifies the injectivity of the sites, assesses the number of wells required and finally estimates the costs of capturing CO2, transporting it to the storage sites and injecting it into the sub-surface. The paper shows that, for the given assumptions, Carbon Capture and Storage (CCS) in the remote high-permeability formation can be significantly cheaper than CCS in the low-permeability storage site. The cost advantage of the considerably higher permeabilities expected in the remote area by far outweighs the cost of transport over the extra distance. This is the case despite applying horizontal drilling and fracturing technologies. The economics of both the low and high permeability formations can be improved markedly by using horizontal rather than vertical wells. However, CCS in the remote high-permeability storage site still retains its cost advantage using this technology. Fracturing increases injectivity considerably for low permeability reservoirs and for both vertical and horizontal wells. However, it does not have a significant effect on reservoirs that have high permeability. Therefore, the technology helps injection in the low-permeability storage site much more than in the remote high-permeability storage formations. However, although under some conditions the relative economics of the low-permeability formation can be improved significantly by fracturing the low-permeability formation, the improvement is not sufficient to reverse the cost disadvantage of the low-permeability storage site. Introduction Ideally a CO2 storage reservoir should have a high permeability, a high pressure gradient, and a high contact area for the injection well. However, if CCS is to be employed on a large scale, the supply of such ideal reservoirs is likely to be significantly less than the demand for storage space. CCS providers will have to deal with thin formations having low permeability, low fracture pressures and high reservoir pressures. Deep saline formations as well as unmineable coal beds fall into this category. However, these formations are often less understood because of the lack of sufficient sub-surface data. GEODISC research on potential Australian CO2 storage sites concluded that the most desirable formations lie in basins far from stationary CO2 sources [Rigg et al. (2001)]. The 50 top emitters of CO2 in Australia, located mostly in East Coast, produce 95% of Australia's total stationary CO2 emissions [CO2CRC report (2004)]. Most of the viable pore space for storage, however, lies in Northwestern waters. The pore space in the vicinity of the stationary sources is mostly in deep saline formations and unmineable coalbeds. These formations have lower potential for storage mainly because they have low-to-very low permeability at depths for optimal CO2 storage (over 800 m) where the CO2 is dense and has adequate seal thickness. Hence, the challenge is to develop cost effective technologies and systems that will allow viable storage in such reservoirs. The technologies considered here are horizontal wells and hydraulic fracturing [Lucier and Zobak (2008)].
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