DGMK/ÖGEW Frühjahrstagung

Celle

25.04.-26.04.2019

Monsees A, Busch B, Subhedar A, Nestler B, Hilgers C

Monsees A

Detailed petrographic analyses as well as petrophysical measurements are well established
standard methods used for reservoir characterization by the E&P industry. Advances in
computational power over the last decade combined with the ongoing challenge of
digitalization present new opportunities regarding fluid flow through porous siliciclastic
sandstones. Based on a case study from a northern German Rotliegend gas reservoir (depth
>5000 m), we introduce a workflow that calibrates numerical flow simulations with geologic lab
data.
X-ray micro computed tomography (μCT) images of samples representing the reservoir
heterogeneity were used to reconstruct the 3D geometry of the studied sandstones. The
digitized rock was integrated with mineralogical data relevant for reservoir quality like mineral
content (Morad et al. 2000, Taylor et al. 2010) and clay coating coverages (Ajdukiewicz et al.
2010, Busch et al. 2017). Petrophysical measurements of porosity (He pycnometry) and
permeabilities were conducted and integrated. Permeability was measured under constant (1.2
MPa) and elevated confining pressures (2-50 MPa), as well as at room temperature and
elevated temperatures (140° C).
Petrographic analyses highlight primary and secondary porosities and the importance of
chemical compaction by quartz grain dissolution. The impact on grain coating clay minerals on
cementation and compaction was assessed. Illite, present on grain surfaces can inhibit
syntaxial cementation, where present at the grain–IGV interface. Where illitic grain coatings
are present at grain-grain contacts it enhances the chemical compaction by enhancing quartz
dissolution. Petrophysically derived porosities range from 0.6-14.5% with permeabilities
ranging from 0.01-781mD. Rock types, defined on characteristics from thin section analyses
show characteristic decreases in reservoir quality at confining pressures from 2 to 50 MPa,
ranging in permeability reductions from below 1 order of magnitude to three orders of
magnitude.
First results are three-dimensional permeability tensors from digitized rocks that are in
agreement with the measured permeabilities of our reservoir samples. The 2-phase flow
models use the different wetting properties of different mineral species derived from 3D μCT
analyses. The modeling of gas flow through a water saturated porous rock shows the migration
of the gas phase along high-perm streaks.