Drilling in the West African subsalt region has revealed the tight, low-porosity character of sandstones resulting from halite cementation. The extent of this cementation directly governs reservoir quality, hydrocarbon distribution, and exploration and development strategies. However, conventional fluid substitution methods based on Gassmann’s theory are inadequate for performing the fluid–solid substitution required to analyze the seismic response of such halite‑cemented sandstones. To address this limitation, we introduce a method for constructing a dedicated rock physics model for halite‑cemented sandstones and demonstrate its use in fluid–solid substitution. The workflow comprises (i) determination of the volumetric fractions of rock constituents from well logs and core data, with total porosity defined as the sum of the halite volume fraction and the effective porosity after cementation; (ii) building an equivalent rock physics model through sequential integration of four established models: the Voigt–Reuss–Hill average model, the modified Xu–White model, the Wood equation, and Gassmann’s relations; (iii) calibration and validation of the model using well‑log and core measurements; and (iv) application of the calibrated model to conduct fluid–solid substitution and total‑porosity variation, yielding elastic parameters for cases where halite is replaced by fluid, fluid is replaced by halite, or total porosity is altered. When applied to the L Gas Field in West Africa, the model predictions exhibit excellent agreement with measured data. Using this validated model, we systematically investigate the elastic properties, seismic amplitude response, and amplitude versus offset behavior of reservoir rocks at varying halite contents, total porosities, and pore‑fluid types within the field.