Author: Xiangnan Liu

Publisher:

Published: 2019

Total Pages: 0

ISBN-13:

As for designing its appropriate development scheme, it is crucial to accurately determine petrophysical properties (e.g., absolute and relative permeability) of a hydrocarbon reservoir, both of which can be traditionally determined either by performing steady-state or unsteady-state experiments or by conducting conventional well tests. However, the laboratory method is time-consuming and its measurements may not be representative for the field-scale cases. Since the conventional well testing theories are based on single-phase flow, it is a challenging task to accurately obtain relative permeability for multiple phases in porous media. Alternatively, flow rates together with pressure responses collected from a wireline formation testing (WFT) tool can be used to interpret absolute and relative permeability as well as capillary pressure of a given formation. Physically, capillary pressure plays an important role during multiphase flow for the WFT measurements, though its effect on the permeability interpretation has not been addressed. In this study, techniques have been developed to simultaneously interpret absolute permeability and relative permeability together with capillary pressure in a naturally fractured carbonate formation as well as to simultaneously interpret three-phase relative permeability and water-oil capillary pressure in a tight carbonate formation from WFT measurements. By using pressure and flow rate field data collected by a dualpacker WFT tool, high-resolution cylindrical near-wellbore numerical models are developed for each dataset. After validating grid quality, simulations and history matching are performed for both the measured pressure drawdown and buildup profiles, while absolute permeability is determined and relative permeability is interpreted with and without considering capillary pressure for the naturally fractured formation. As for the tight carbonate formation, water-oil relative permeability, oil-gas relative permeability, and water-oil capillary pressure are interpreted based on power-law functions and under the assumption of a water-wet reservoir and an oil-wet reservoir, respectively. Subsequently, three-phase relative permeability for the oil phase is determined by using the modified Stone II model. Compared with the experimentally measured values, relative permeability interpreted with consideration of capillary pressure has a better match than those without considering capillary pressure in the naturally fractured carbonate formation. In such a formation, absolute permeabilities in the vertical and the horizontal directions of the upper layer are determined to be 201.0 mD and 86.4 mD, respectively, while those of the lower layer are found to be 342.9 mD and 1.8 mD, respectively. Such a large vertical permeability of the lower layer reflects the contribution of the extensively distributed natural fractures in the vertical direction. In the tight carbonate formation, both the relative permeability and the capillary pressure of a water-oil system interpreted under an oil-wet condition match well with the measured values, while the relative permeability of an oil-gas system and the three-phase relative permeability bear a relatively high uncertainty. Not only is the tight reservoir determined as oil-wet, but also the initial oil saturation is found to impose an impact on the interpreted water relative permeability under an oil-wet condition. Changes in water and oil viscosities and mud filtrate invasion depth affect the range of the movable fluid saturation of the interpreted water-oil relative permeabilities.