Abstract
There are direct and indirect methods to define a gas-oil contact (GOC) in a petroleum reservoir. The direct method requires drilling a well to penetrate prospective fluid contacts. The indirect methods, which include, compositional grading simulation (CGS), do not require evaluating prospective GOC with a dedicated well. However, the CGS technique is currently deemed not applicable in cases of limited pressure-volume-temperature (PVT) dataset.
By exploiting a new framework developed by Okoh et al. (2020), this paper demonstrates the applicability of CGS to petroleum reservoirs characterized by limited PVT dataset. This method entails estimating the degree of under-saturation of a given fluid sample at a known sample depth. Using known fluid gradient and estimated saturation pressure gradient of the fluid sample, this degree of under-saturation is converted to its equivalent depth to estimate a potential GOC within a connected reservoir. Empirical models for estimating saturation pressure gradient and bubble-point pressure of an oil sample at in-situ conditions are presented. Considering the need for a reliable estimate of the in-situ bubble-point pressure, different bubble-point empirical models are examined for their suitability and accuracy.
Several examples of saturated and undersaturated reservoirs from the Niger Delta are used for validation tests. Overall, the bubble-point correlation by Ikiensikimama and Ogboja (2009) was found to be the most appropriate for the intended application. Additionally, the validation tests confirmed the robustness of the proposed method for predicting potential GOC in petroleum reservoirs that have limited PVT dataset. While the scope of validation of this paper has been limited to the Niger Delta, we expect the proposed method to perform satisfactorily in the treatment of similar problems in other basins.
