Anthropogenic carbon dioxide (CO₂) emissions are a major driver of global climate change, resulting in a growing demand for technologies to abate emissions from power generation and carbon-intensive industrial processes. Therefore, carbon capture and storage (CCS) has become a key mitigation option especially for those industries that still have technical or economic constraints to full de-carbonization. The last step of the CCS chain is geological storage of CO₂, which involves injecting the captured CO₂ into suitable subsurface formations where it can be isolated from the atmosphere for sufficiently long time scales. The main geological targets for CO₂ storage are deep saline aquifers and depleted oil and gas reservoirs. Saline formations are attractive because of their widespread distribution and potentially large storage capacity. Depleted hydrocarbon reservoirs have a number of advantages related to their prior exploration and production history. Seismic surveys, well logs, core measurements, pressure data, production histories and existing reservoir models may contain a wealth of information that can be used to evaluate reservoir architecture, storage capacity, injectivity and seal integrity. Many hydrocarbon reservoirs have also been shown to retain fluids over geological time scales, suggesting that they could be used to store CO₂. At typical geological storage depths (generally > ~ 800 m depending on local pressure and temperature conditions), CO₂ is typically in the form of a dense or supercritical fluid. The increased density under these conditions means that large quantities of CO₂ can be stored in reservoir pore space. But, in general, CO₂ is less dense and less viscous than formation brine, leading to a complex multiphase flow system after injection. Injection-induced pressure gradients initially dominate fluid flow but buoyancy, capillary forces, reservoir heterogeneity, wettability, and fluid-rock interactions progressively influence the migration and redistribution of plumes. The injected CO₂ does not therefore stay concentrated around the injection well. It can migrate laterally via high permeability pathways and vertically under buoyancy, accumulate under low permeability geological barriers, become disconnected and immobilized in pore space, dissolve into formation water and ultimately participate in geochemical reactions with reservoir minerals. Consequently, the spatial distribution and physical state of the stored CO₂ change during both the injection and post-injection periods. This evolution is largely driven by reservoir heterogeneity. CO 2 distributions can be highly nonuniform due to variations in permeability, porosity, pore-throat size, capillary entry pressure, facies architecture, fractures, and mineralogy. Preferential migration in permeable layers can be associated with local accumulation below capillary barriers and small-scale heterogeneity can determine whether CO₂ remains connected or becomes immobilized during subsequent brine imbibition. These processes provide an important connection between petroleum reservoir physics and geophysical monitoring as the resulting fluid distribution affects the effective physical properties measured by geophysical techniques. Hence, the long-term storage security is not only dependent on the capacity of the formation to receive CO 2 but also on the processes that progressively restrict its mobility. Storage reliability assessments require understanding of how the CO₂ migrates, how much remains in the target storage complex, how its saturation changes, and how it evolves from a mobile free phase to more effectively trapped states. One of the basic technical requirements of geological CO 2 storage is to monitor such changes.

Iftekhar Ahmed Shakib,"Geophysical Detection and Monitoring of CO₂ Trapping Mechanisms in Geological Reservoirs" International Journal of Advanced Multidisciplinary Research and Educational Development, V2(3): Page(1528-1567) May - June 2026. ISSN: 3107-6513. www.ijamred.com. Published by Scientific and Academic Research Publishing.