<p>Characterizing pore types in carbonate rocks is essential for understanding their reservoir properties, such as water saturation, porosity, and permeability, as well as their reservoir quality and dynamic behavior. The aim and objective of this study are primarily to identify the pore types and then, as an innovative approach, to specify whether the fluid within the pores in the reservoir is producible or remains immobile. To achieve this goal, bound and free fluid pore types are defined using nuclear magnetic resonance logs and post-stack 3D seismic data from an Iranian oil reservoir for the Main Ilam carbonate Formation. Initially, the fullset of logs for two wells (A and B) were used to determine porosity, lithology, and fluid content, followed by the nuclear magnetic resonance log to identify macro, meso, micro, and clay pore types. Subsequently, in well A, the results were validated through pore-size distribution analysis of the available core samples. Afterward, a rock physics model for carbonated rocks was used to estimate compressional velocity and density based on petrophysical evaluation and pore-type calculation. The correlation coefficients for compressional velocity in wells A and B of the Main Ilam Formation were 92% and 80%, respectively. The strong correlation among measured and modeled values verified that nuclear magnetic resonance data effectively estimates pore-type variations. Furthermore, bounded fluid was calculated based on the clay and micro pores, while free fluid was calculated based on the meso and macro pores in both wells. Finally, this information was mapped into the 3D seismic cube using inversion and multi-attribute regression analysis.</p> Graphical abstract <p></p>