The Significance of a Pressure Gradient on a Carbon Dioxide Storage Site
Engineering Honours Degree 2007
University of Adelaide
The underground storage of carbon dioxide, CO2, is one technology currently being evaluated for its potential to reduce atmospheric carbon dioxide emissions. Geological storage of CO2 involves the capture of CO2 from sources such as fossil fuel fired power stations, which is then transported via pipe line to geological storage sites, such as depleted oil and gas reservoirs or saline formations.
In this study, a potential storage site in the Browse Basin, the Carbine Ponded Turbidite, which is a closed lenticular brine reservoir, was investigated. Geological storage of CO2 in saline formations have the advantage because the saline formations are distributed more greatly around the world. Disadvantages include that they are generally much less understood than that of hydrocarbon bearing formations.
The required amount of CO2 to be injected into the formation was 1.473million standard cubic meters per day. Being that the reservoir is a closed system, producing brine to relieve injection pressure was considered. Numerical simulation was employed for a majority of the study. It was found that the optimum injection and production strategy was to inject low into the formation and produce from low in the formation. The optimum well design consisted of a simple vertical injection and vertical production well in a two spot well pattern for the base case. This base case was then simulated for 1000 years to assess the risk of CO2 escaping the reservoir. According to the simulation the CO2 posed no risk of escaping.
Sensitivities were then considered with respect to the base case. Factors considered include permeability, distance between injection and production wells and boundary conditions. To investigate the effect varying these parameters would have on the pressure gradient in the Carbine Ponded Turbidite. It was found that permeability affects both injectivity and the migration of CO2. For low permeability an increase in the pressure gradient can relieve injection pressure. For high permeability a decrease in the pressure gradient can slow migration of CO2. It was also determined that by increasing the pressure gradient the number of wells required for injection and production could be reduced in low permeability cases.
Boundary conditions affect the pressure gradient. If open boundary conditions exist then a pressure gradient can be established between the injector and boundary, and this can further help to distribute CO2 through the reservoir and increase the sequestering process. It was also discovered that the pressure gradient plays a major role in production injection scenarios. For example, it can be used to control the migration rate of CO2 as well as the direction of the migration.