<abstract xmlns="http://www.w3.org/1999/xhtml"><p> The study employs numerical calculations in the characterization of reservoir sandstone samples based on high-resolution X-ray computed microtomography. The major goals were to determine porosity through pore size distribution, permeability characterization through pressure field, and structure impact on rock strength by simulation of a uniaxial compression test. Two Miocene samples were taken from well S-3, located in the eastern part of the Carpathian Foredeep. Due to the relation between sample size and image resolution, two X-ray irradiation series with two different sample sizes were performed. In the first approach, the voxel side was 27 μm and in the second it was up to 2 μm. Two samples from different depths have been studied here. Sample 1 has petrophysical features of conventional reservoir deposits, in contrast to sample 2. The approximate grain size of sample 1 is in the range 0.1-1.0 mm, whereas for sample 2 it is 0.01-0.1 mm with clear sedimentation lamination and heterogenic structure. The porosity, as determined by μCT, of sample 1 is twice (10.3%) that of sample 2 (5.3%). The equivalent diameter of a majority of pores is less than 0.027 mm and their pore size distribution is unimodal right-hand asymmetrical in the case of both samples. In relation to numerical permeability tests, the flow paths are in the few privileged directions where the pressure is uniformly decreasing. Nevertheless, there are visible connections in sample 1, as is confirmed by the homogenous distribution of particles in the pore space of the sample and demonstrated in the particle flow simulations. The estimated permeability of the first sample is approximately four times higher than that of the second one. The uniaxial compression test demonstrated the huge impact of even minimal heterogeneity of samples in terms of micropores: 4-5 times loss of strength compared to the undisturbed sample. The procedure presented shows the promising combination of microstructural analysis and numerical simulations. More specific calculations of lab tests with analysis of variable boundary conditions should be performed in the future.</p></abstract>

The study employs numerical calculations in the characterization of reservoir sandstone samples based on high-resolution X-ray computed microtomography. The major goals were to determine porosity through pore size distribution, permeability characterization through pressure field, and structure impact on rock strength by simulation of a uniaxial compression test. Two Miocene samples were taken from well S-3, located in the eastern part of the Carpathian Foredeep. Due to the relation between sample size and image resolution, two X-ray irradiation series with two different sample sizes were performed. In the first approach, the voxel side was 27 μm and in the second it was up to 2 μm. Two samples from different depths have been studied here. Sample 1 has petrophysical features of conventional reservoir deposits, in contrast to sample 2. The approximate grain size of sample 1 is in the range 0.1-1.0 mm, whereas for sample 2 it is 0.01-0.1 mm with clear sedimentation lamination and heterogenic structure. The porosity, as determined by μCT, of sample 1 is twice (10.3%) that of sample 2 (5.3%). The equivalent diameter of a majority of pores is less than 0.027 mm and their pore size distribution is unimodal right-hand asymmetrical in the case of both samples. In relation to numerical permeability tests, the flow paths are in the few privileged directions where the pressure is uniformly decreasing. Nevertheless, there are visible connections in sample 1, as is confirmed by the homogenous distribution of particles in the pore space of the sample and demonstrated in the particle flow simulations. The estimated permeability of the first sample is approximately four times higher than that of the second one. The uniaxial compression test demonstrated the huge impact of even minimal heterogeneity of samples in terms of micropores: 4-5 times loss of strength compared to the undisturbed sample. The procedure presented shows the promising combination of microstructural analysis and numerical simulations. More specific calculations of lab tests with analysis of variable boundary conditions should be performed in the future.

Numerical Approach in Recognition of Selected Features of Rock Structure from Hybrid Hydrocarbon Reservoir Samples Based on Microtomography

Studia Geotechnica et Mechanica

This work is licensed under the Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 License.

The study employs numerical calculations in the characterization of reservoir sandstone samples based on high-resolution X-ray computed microtomography. The...

Numerical Approach in Recognition of Selected Features of Rock Structure from Hybrid Hydrocarbon Reservoir Samples Based on Microtomography

Online veröffentlicht: 17. Mai 2017

Seitenbereich: 13 - 26

DOI: https://doi.org/10.1515/sgem-2017-0002

Schlüsselwörter
compression test, flow paths, porosity, sandstone

© by Łukasz Dominik Kaczmarek

This work is licensed under the Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 License.

Numerical Approach in Recognition of Selected Features of Rock Structure from Hybrid Hydrocarbon Reservoir Samples Based on Microtomography

Online veröffentlicht: 17. Mai 2017

Seitenbereich: 13 - 26

DOI: https://doi.org/10.1515/sgem-2017-0002

Schlüsselwörtercompression test, flow paths, porosity, sandstone

© by Łukasz Dominik Kaczmarek

This work is licensed under the Creative Commons Attribution-NonCommercial-NoDerivatives 4.0 License.

Schlüsselwörter
compression test, flow paths, porosity, sandstone