Electrical properties are important parameters to quantitatively calculate water saturation in oil and gas reservoirs by well logging interpretation.

After long-term production by water injection, the conductivity features of oil reservoirs are changed, leading to difficulties in calculating remaining oil saturation by traditional well-logging techniques. There are some specific phenomena relating to petrophysical properties in water-flooded layers, and a deep investigation of them could help us understand resistivity changes of rocks during the water-injection process. We compared traditional mixed-fluid resistivity methods and determined their drawbacks. In addition, we revised the theoretical models and came up with a novel method to calculate mixed-fluid resistivity. The displacement process was divided into three stages: non-water-flooded stage, low and medium water-flooded stage, and high water-flooded stage. To study the relationships between rock resistivities and water saturations when injecting fresh-/saltwater, we used digital rock numerical methods. We first constructed 3D digital rock models based on the process-based method, and then we obtained oil and water distributions in the pore space by the pore morphology method. When resistivities of every component in digital rock models were assigned, rock resistivities could be calculated in different water saturations by the finite-element method. We found that in the case of freshwater injection, the relationship between water saturations and rock resistivities formed an S-shaped curve, but in the case of saltwater injection, if the injection water salinity was higher, the rock resistivity would be decreased by increasing the water saturation. In different rock heterogeneity and wettability conditions, these curves showed similar shapes and trends. Combined with resistivity logging data, this novel approach was used in the interpretation of a real oil well. Compared with the existing models in the interpretation practices, this new model better matched the real-field saturations and improved the accuracy of saturation interpretation in the studied water-flooded oil reservoir.

Total water saturation is an important parameter for calculating the free gas content of shale gas reservoirs. Owing to the limitations of the Archie

The oil-based mud filtrate will invade the formation under the overbalanced pressure during drilling operations. As a result, alterations will occur to the nuclear magnetic resonance (NMR) response characteristics of the original formation, causing the relaxation time of the NMR T₂ spectrum of the free fluid part to move towards a slower relaxation time. Consequently, the subsequent interpretation and petrophysical evaluation will be heavily impacted. Therefore, the actual measured T₂ spectrum needs to be corrected for invasion. For this reason, considering the low-porosity and low-permeability of sandstone gas formations in the East China Sea as the research object, a new method to correct the incorrect shape of the NMR logging T₂ spectrum was proposed in three main steps. First, the differences in the morphology of the NMR logging T₂ spectrum between oil-based mud wells and water-based mud wells in adjacent wells were analyzed based on the NMR relaxation mechanism. Second, rocks were divided into four categories according to the pore structure, and the NMR logging T₂ spectrum was extracted using the multidimensional matrix method to establish the T₂ spectrum of water-based mud wells and oil-based mud wells. Finally, the correctness of the method was verified by two T₂ spectrum correction examples of oil-based mud wells in the study area. The results show that the corrected NMR T₂ spectrum eliminates the influence of oil-based mud filtrate and improves the accuracy of NMR logging for calculating permeability.