The economics of the storage of CO2 in underground reservoirs in Australia have been analysed as part of the Australian Petroleum Cooperative Research Centre’s GEODISC program. The economic analyses in the paper are based on cost estimates generated by a CO2 storage technical/economic model developed at the beginning of the GEODISC project. The estimates rely on data concerning the characteristics of geological reservoirs in Australia. The uncertainties involved in estimating the costs of such projects are discussed and the economics of storing CO2 for a range of CO2 sources and potential storage sites across Australia are presented.The key elements of the CO2 storage process and the methods involved in estimating the costs of CO2 storage are described and the CO2 storage costs for a hypothetical, but representative storage project in Australia are derived. The effects of uncertainties inherent in estimating the costs of storing CO2 are shown.The analyses show that the costs are particularly sensitive to parameters such as the CO2 flow rate, the distance between the source and the storage site, the physical properties of the reservoir and the market prices of equipment and services. Therefore, variations in any one of these inputs can lead to significant variation in the costs of CO2 storage. Allowing for reasonable variations in all the inputs together in a Monte Carlo simulation of any particular site, then a large range of total CO2 storage costs is possible. The effect of uncertainty for the hypothetical representative storage site is illustrated.The impact of storing other gases together with CO2 is analysed. These gases include methane, hydrogen sulphide, nitrogen, nitrous oxides and oxides of sulphur, all of which potentially could be captured together with CO2. The effect on storage costs when varying quantities of other gases are injected with the CO2 is shown.Based on the CO2 storage cost estimates and the published costs capturing CO2 from industrial processes, the economics are shown of combined capture and storage (that is, the sequestration process as a whole) for the major CO2 generation sites across Australia combined with potential compatible storage sites. Examples are shown of the volumes of CO2 that could be sequestered economically depending on the level of the carbon credit in a hypothetical carbon credit trading regime. Purely as an illustration, assuming hypothetically that a real carbon credit of US$50 per tonne applied and that the cost of capture was US$40 per tonne across the board, then preliminary indications are that, ignoring tax considerations, it would be economic to store about 180 million tonnes per year of CO2. This is equivalent to about 70% of the annual CO2 emissions from stationary sources in Australia in 2000.

This paper argues that any capacity estimation method requires a combination of geological, engineering and economic analysis in order to provide rigorous capacity estimates. It also argues that the classification of capacity estimates should follow concepts in the existing SPE Petroleum Resource Management System as closely as possible. The Energy & Environmental Research Centre (EERC) (Gorecki et al., 2009) have developed a definition of "practical storage capacity" that parallels the definition of petroleum reserves as "the quantity of hydrocarbons which are anticipated to be commercially recovered from known accumulation at a given date forward", but the EERC acknowledge that there is currently a problem with implementing a price of carbon. This paper develops the economic analysis further than the EERC. Like the EERC, we demonstrate that analytical and numerical injectivity modelling based on geological models of the subsurface can help determine practical storage capacity. In doing this, the paper makes observations about methods for estimating storage capacity, shows results of reservoir simulations and economic analyses, draws on SPE and internationally accepted methodologies and definitions of petroleum resources and discusses how equivalent definitions can be applied to storage capacity. Finally, the paper provides recommendations for an improved CO2 storage capacity classification system.

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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)].

This paper presents geoengineering and economic sensitivity analyses and assessments of the Wunger Ridge flank carbon capture and storage (CCS) site. Both geoengineering and economics are needed to derive the number of wells required to inject a certain amount of CO 2 for a given period.A numerical reservoir simulation examines injection rates ranging from 0.5 to 1.5 million tonnes of CO 2 year for 25 years of injection. Primary factors affecting the ability to inject CO 2 include permeability, formation fracture gradient, aquifer strength, and multiphase flow functions. Secondary factors include the solubility of CO 2 in the formation brine, injection well location with respect to the flow barriers/low-permeability aquifers, model geometry including faults, grid size and refinement, and injection well type. Less significant factors include hydrodynamic effects.The economics are assessed using an internally developed technoeconomic model. The model optimizes the CO 2 injection cost on the basis of geoengineering data and recent equipment costs. The overall costs depend on the initial costs of CO 2 separation and source-to-sink distances and their associated pipeline costs. Secondary cost variations are highly dependent on fracture gradient, permeability, and CO 2 injection rates. Depending on the injection characteristics, the specific cost of CO 2 avoided is between AUS 62 and 80 per tonne.