Coupled Numerical Simulation Modelling of Depleted Gas Reservoir for Carbon Dioxide Sequestration

Carbon Capture and Storage (CCS) is certainly the most important energy transition technology for the petroleum industry. The main objective of this process is to sequester carbon dioxide (CO₂) in underground reservoirs/structures safely for many years with aim of reducing the greenhouse gas emissions and mitigating the global climate change impacts. Generally, there are four target areas for underground carbon storage. These consist of depleted oil or gas reservoirs, saline aquifers, coal beds and conventional oil reservoirs with a potential for enhance oil recovery (CO₂-EOR). The current trend in the industry is mainly focused on the first two categories above. Large solubilization capacity of brine with multiple trapping mechanisms made the saline aquifer an interesting target while the existing knowledge, infrastructure in place and good injectivity are the most important factors for depleted hydrocarbon reservoirs.

There are many published case studies in the literature focusing on CO₂ storage in depleted gas reservoirs, however the majority of them apply to conventional dynamic flow, some with an added caprock integrity study. During producing life and CO₂ injection phase in a depleted hydrocarbon reservoir, pores pressure and fluid saturation in the pore space changes affecting the fluid flow, geochemical equilibrium, and geomechanics properties of the reservoir. It is essential to establish an integrated coupled model to capture the inter-related effects of dynamic fluid flow, geochemistry and geomechanics on the storage capacity and integrity of the reservoir. During CO₂ injection into depleted gas reservoirs, it is anticipated that there will be mineral dissolution or precipitation effects due to geochemical reactions that alter the rock porosity and permeability. This in turn will result in changes of the rock strength. Basically, these dynamic fluid flow, geochemical, and geomechanical changes are inter-related. Hence it is important to use an integrated coupled model that captures all these effects caused by CO₂ injection to evaluate suitability of the reservoir for long-term CO₂ storage.

In this study, CMG's compositional simulator GEM is used to couple the dynamic fluid flow, the geochemistry, and the geomechanics to study the effects of all three changes. This provides a more accurate CO₂ storage capacity estimation approach along with valuation of geomechanics such as subsidence at top of the reservoir and surface which determine the integrity of storage. For this paper a sector model extracted from a full field depleted gas reservoir with a single producer well which later converted to CO₂ injector. The results of the coupled model show approximately 1% of injected CO₂ in mole are mineralized in 3000 years considering geochemistry impact in the model. This translates to an equivalent increasing of storage capacity of 5-10% compared to conventional dynamic model.

The results of the geochemical reactions show that initially there is some dissolution during the CO₂ injection, after that within couple of hundred years there are precipitation and finally there is CO₂ mineralization after 3000 years. This is mainly due to the expansion of the CO₂ plume from the gas zone to the water zone.

It is observed that during the production there is a subsidence of about 22 cm at the top of the reservoir and there is pore collapse due to pressure depletion in the reservoir rock. At the end of injection, subscience recovered by average of 20% of its maximum during the production. The injection can be continued until the initial reservoir pressure is reached without breaching caprock however due to rate constraint and risk of induced fracture, the injection rate is kept constant at 0.5 MMSCF/day.