A numerical investigation into the potential to enhance natural gas recovery in water-drive gas reservoirs through the injection of CO₂.

Abstract

The injection of carbon dioxide (CO₂) into oil reservoirs for the purpose of enhancing recovery has been performed for decades. Conversely, the injection of CO₂ into natural gas reservoirs has received very little attention, primarily due to the typically high recovery achievable under primary depletion. This high recovery is however associated with volumetric gas reservoirs only. If the reservoir is in the presence of an active water-drive, recovery can be considerably lowered. This is caused by pressure maintenance and the trapping of gas, rendering a volume of gas immobile. Consequently, any technique that reduces reservoir pressure and/or retards the influx of the aquifer will enable natural gas recovery to be enhanced. In this thesis, the injection of CO₂ has been proposed as a method of retarding the influx of the aquifer. Favourable fluid properties between the injected CO₂ and natural gas also allow the displacement of natural gas towards the production wells with minimal mixing. This thesis investigates the nature of the effects of a number of parameters deemed potentially influential on the displacement of natural gas by CO₂ and the ability to produce and enhance recovery with as low a producing CO₂ concentration as possible. Parameters chosen include uncontrollable reservoir and fluid properties such as permeability, thickness, diffusion coefficients and salinity. Controllable factors are also investigated, such as the timing of injection, production and injection rates and the type of wells employed. This investigation was conducted through the use of numerical simulation. Simulations were first performed on a simple, conceptual model in order to understand the key processes involved in the CO₂ enhanced gas recovery process. The results of these studies were then applied to a more complex numerical investigation involving a model of the Naylor gas field. The results of the initial studies found that the parameters which determined the extent of viscous and gravity forces, such as permeability, thickness and formation dip, were the most influential in determining the stability of the displacement, and consequently the recovery achievable at the breakthrough of CO₂ at the production well. The fluid properties, such as water salinity and the diffusion coefficient, were found to have less of an impact than the reservoir properties. Efficient displacement in a non-dipping reservoir was possible with either viscous or gravity dominated displacement, while only gravity stable displacement was preferred in a dipping reservoir. The primary recovery efficiency did however dictate where the injection of CO₂ should be targeted in order to achieve incremental recovery with the lowest producing CO₂ concentration. Due to the low primary recovery efficiency, the injection of CO₂ should be targeted in high permeability, non-dipping reservoirs. The presence of heterogeneity accelerated the breakthrough of CO₂, and so it was shown that delaying the injection of CO₂ was beneficial in maximising the recovery at the initial breakthrough of CO₂. However, once CO₂ had reached the production well, the rate of increase in CO₂ production was considerably more rapid if injection was delayed. The choice of the timing of injection and the ability to maximise incremental recovery is therefore heavily influenced by the maximum allowable producing CO₂ concentration, which will be determined by the economics of the project. The investigation into the other controllable parameters showed that the operational strategies which either lowered the susceptibility for CO₂ to cone into the production well, or which mitigated against the uneven advancement of CO₂ due to heterogeneity were preferred. Ultimately this study showed that the injection of CO₂ can effectively retard the influx of the aquifer and efficiently displace natural gas towards the production well. By understanding the mechanisms involved in this displacement process, operational parameters can be optimised accordingly to maximise natural gas recovery with the lowest producing CO₂ concentration. The extent of incremental recovery is subsequently determined by the maximum producing CO₂ concentration allowable, as determined by the economics of the project.