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.

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