CO₂ Injection to Mitigate Condensate Banking in a Low-Permeability Reservoir

One of the main challenges of producing tight or low-permeability gas reservoirs is condensate banking when production starts as the reservoir pressure drops below the dewpoint pressure. Condensate banking causes formation damage and subsequently damages production. The normal procedure to mitigate condensate banking is to hydraulically fracture the well to bypass the condensate bank and improve production from that well. Modeling the condensate banking along the hydraulic fracture is critical to understanding the loss of productivity.

We investigated the feasibility of simulating a cyclic CO₂ injection scheme to mitigate formation damage due to gas condensate dropout in a low-permeability gas reservoir. The field was modeled using a tartan grid to be able to model the hydraulic fracture explicitly. In addition to the hydraulic fracture, the study examined how much of a role the condensate-gas ratio (CGR) plays in the condensate banking and how to best position a well in a low-, medium-, and high-CGR fluid. For the mitigation phase, different cyclic parameters such as injection rate, injection pressure, and soaking time for the cyclic CO₂ injection were considered.

The study found that the volume of the GCR played a critical role in determining injection rates and pressure to best be able to mitigate damage due to condensate banking.