Relative permeability and capillary pressure are essential information for reservoir modeling, as they impact production optimization and reservoir management. Obtaining this data from special core analysis can take a significant amount of time. Furthermore, it can be challenging to guarantee that the core is restored to its original reservoir wettability state. Additional challenges include cost, scale, and the presence of contamination or alteration. Other emerging techniques, like digital rock, face similar issues. A new workflow has been designed to address those challenges and complement the traditional core analysis offering, by obtaining relative permeability and capillary pressure in-situ from wireline formation tester (WFT) and open hole logging measurements. In this workflow, a near-wellbore reservoir model is built to simulate the mud-filtrate invasion. This reservoir model, combined with an electromagnetic model, simulates resistivity logs, and subsequent pressure transient and mud-filtrate cleanup processes induced by WFT formation testing. Petrophysical log analysis, using array resistivity, nuclear magnetic resonance, and dielectric measurements, is performed to provide prior information for the model initialization. Vertical interference testing from WFT at the same depth provides permeability anisotropy. An optimization engine is employed to update the selected reservoir model parameters until the simulated resistivity logs, pressure transient, and water-cut data match their measured counterparts. Relative permeability and capillary pressure are estimated together with other parameters including mud-filtrate invasion volume and permeability. Both stochastic and deterministic methods are used for the inversion. The deterministic method is cost-effective if a good initial model can be obtained, while the stochastic method is able to find the minimization function's global minimum but needs high computational effort. This workflow was applied to one well in the Ahmadi field in Kuwait, targeting an inter-tidal deposit. In-situ relative permeability and capillary pressure curves were obtained by the deterministic and stochastic methods using formation testing data and petrophysical logs acquired over the interval. The results are consistent between the two methods and representat the effective formation properties in the surveyed interval. This case study demonstrates that it is possible to obtain in-situ relative permeability and capillary pressure data from commonly acquired wireline measurements. The delay in obtaining the relative permeability and capillary pressure data is significantly reduced compared to special core and digital core analysis techniques. Since the measurement is performed downhole, it doesn't suffer from the doubts that surround the core samples restoration process to original reservoir conditions. The formation volume investigated by this survey, in the order of several feet, represents the formation macroscopic properties, thus bridging the gap between core scale and reservoir scale.

The Greater Burgan field has been producing since 1946 from a series of highly permeable Cretaceous reservoirs. Recently, a series of more complex reservoirs has been reassessed using advanced logging and wireline formation tester (WFT) technologies. The techniques employed in the reassessment include fluid-quality (viscosity and presence of tar) mapping using nuclear magnetic resonance (NMR) log data and shallow invasion measurements using multifrequency, multispacing dielectric data. In addition, the dielectric logs provide a direct measurement of the Archie m exponent in water zones. Improvements in formation evaluation achieved by integrating these results with conventional logs included better differentiation of moveable from residual hydrocarbon, identification of variations in formation water salinity, and maps of oil-quality variation versus depth and across the field. These techniques were applied to three case studies. In the first case study, formation evaluation was conducted in an Upper Cretaceous carbonate formation of unknown water salinity. The combination of dielectric logs and NMR enabled identification of water-bearing and residual oil zones where formation water salinity could be determined. The analysis revealed increasing water salinity with depth. Dielectric logging also provided a direct evaluation of Archie's m exponent in the water zones, in the absence of special core analysis. The NMR highlights variations in oil quality from one well to another. In the second case study, a viscous oil layer located in the middle of a water zone in a Middle Cretaceous reservoir was evaluated. Moveable oil was identified by radial oil saturation variation close to the borehole detected by the dielectric log measurement. The interpretation was verified by the first oil sample ever recovered in this layer. In the final case study, in a Lower Cretaceous reservoir, dielectric measurements provided accurate estimates of residual oil saturation required for planning enhanced oil recovery projects. The results obtained from the application of the multifrequency dielectric dispersion and diffusion-NMR as confirmed with WFT sampling bring new insight to the evaluation of challenging formations within the Burgan field.