An integrated multidomain approach to modeling subsurface CO₂ storage streamlined decision making, reduced uncertainties, and enhanced project predictability. Integration between geology, geophysics, and reservoir engineering was key to site selection and determining boundary conditions. Geomechanics was used to define fracture gradients, and reservoir engineering, production, and well integrity domains identified operating parameters that minimize risk.

An oil company has targeted two depleted gas and condensate fields in the Middle East for subsurface storage of CO₂. Dynamic modeling of CO₂ storage—including selecting boundary conditions and optimizing injection—requires integration across multiple domains. Leveraging its extensive multidisciplinary subsurface expertise and experience, SLB worked closely with the oil company's team on a study to estimate the potential storage capacity of various reservoirs in the two fields.

The workflow started with defining the boundary conditions for the geological model. These conditions have a direct impact on storage capacity. The team concluded that the main structure was surrounded on three sides by sealing faults. However, on the fourth side, the model had to be extended using available seismic and geological input to capture the boundary conditions for CO₂ injection. The updated model enables simulating the effect of CO₂ injection and the resulting changes in pressure and temperature on the geomechanical properties of overburden and underburden rocks.

Next, several 1D mechanical earth models (MEMs) were created to represent the pore-pressure conditions observed initially (before depletion), currently (after depletion), and after injection. The teams evaluated the robustness of the MEMs by contrasting predicted wellbore stability with drilling events and hole conditions derived from image and caliper logs.

Using the models, a correlation was created between reservoir pore pressure and fracture gradient. This correlation was used to determine the maximum bottomhole injection pressure (BHIP) for each well across the injection period. The objective was to enable steadily increasing the injection pressure as reservoir pressure increased, without exceeding the changing fracture pressure across the duration of CO₂ injection.

Finally, the teams created and calibrated well models to capture CO₂ phase, pressure, and temperature behavior during injection. These models together with the reservoir pressure and maximum BHIP determined from earlier simulations were used to compute the maximum injection rates and conduct dynamic simulations of CO₂ injection. This workflow ensures that CO₂ injection takes place within prescribed operating limits, taking into account the expected thermal expansion.

In summary, multidomain integration fostered a holistic approach to CO₂ sequestration, comprehensively addressing technical, environmental, and operational challenges and maximizing the probability of project success.