Simultaneous Interpretation of Relative Permeability and Capillary Pressure for a Naturally Fractured Carbonate Formation from Wireline Formation Testing

2019 ◽  
Author(s):  
Xiangnan Liu ◽  
Daoyong Yang ◽  
Andrew Chen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Simultaneous Interpretation ◽  
Carbonate Formation ◽  
Naturally Fractured ◽  
Fractured Carbonate

Simultaneous Interpretation of Relative Permeability and Capillary Pressure for a Naturally Fractured Carbonate Formation From Wireline Formation Testing

2019 ◽  
Vol 142 (3) ◽  
Author(s):  
Xiangnan Liu ◽  
Daoyong Yang ◽  
Andrew Chen
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Lower Layer ◽  
Numerical Models ◽  
Vertical Direction ◽  
Dual Porosity ◽  
Absolute Permeability ◽  
Carbonate Formation ◽  
Naturally Fractured ◽  
Fractured Carbonate

Abstract In this paper, pragmatic and robust techniques have been developed to simultaneously interpret absolute permeability and relative permeability together with capillary pressure in a naturally fractured carbonate formation from wireline formation testing (WFT) measurements. By using two sets of pressure and flow rate field data collected by a dual-packer tool, two high-resolution cylindrical near-wellbore numerical models are developed for each dataset on the basis of single- and dual-porosity concepts. Then, simulations and history matchings 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. Compared to the experimentally measured relative permeability curves for the same formation collected from the literature, relative permeability interpreted with consideration of capillary pressure has a better match than those without considering capillary pressure. Also, relative permeability obtained from dual-porosity models has similar characteristics to those from single-porosity models especially in the region away from the endpoints, though the computational expenses with dual-porosity models are much larger. 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.

scholarly journals Geological Model of a Storage Complex for a CO2 Storage Operation in a Naturally-Fractured Carbonate Formation

Geosciences ◽  
2018 ◽  
Vol 8 (9) ◽  
pp. 354 ◽  
Author(s):  
Yann Le Gallo ◽  
José de Dios
Keyword(s):  
Co2 Storage ◽  
Advanced Characterization ◽  
Fracture Network ◽  
Geological Model ◽  
Fracture Density ◽  
Deep Saline Aquifer ◽  
Matrix Permeability ◽  
Carbonate Formation ◽  
Naturally Fractured ◽  
Fractured Carbonate

Investigation into geological storage of CO2 is underway at Hontomín (Spain). The storage reservoir is a deep saline aquifer formed by naturally fractured carbonates with low matrix permeability. Understanding the processes that are involved in CO2 migration within these formations is key to ensure safe operation and reliable plume prediction. A geological model encompassing the whole storage complex was established based upon newly-drilled and legacy wells. The matrix characteristics were mainly obtained from the newly drilled wells with a complete suite of log acquisitions, laboratory works and hydraulic tests. The model major improvement is the integration of the natural fractures. Following a methodology that was developed for naturally fractured hydrocarbon reservoirs, the advanced characterization workflow identified the main sets of fractures and their main characteristics, such as apertures, orientations, and dips. Two main sets of fracture are identified based upon their mean orientation: North-South and East-West with different fracture density for each the facies. The flow capacity of the fracture sets are calibrated on interpreted injection tests by matching their permeability and aperture at the Discrete Fracture Network scale and are subsequently upscaled to the geological model scale. A key new feature of the model is estimated permeability anisotropy induced by the fracture sets.

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