Mbia, Ernest Ncha4; Fabricius, Ida Lykke1; Krogsbøll, Anette5; Frykman, Peter7; Dalhoff, Finn4
1 Department of Civil Engineering, Technical University of Denmark2 Section for Geotechnics and Geology, Department of Civil Engineering, Technical University of Denmark3 Center for Energy Resources Engineering, Center, Technical University of Denmark4 Vattenfall A/S5 Department of Geology and Geotechnical Engineering, Technical University of Denmark6 Geological Survey of Denmark and Greenland7 Geological Survey of Denmark and Greenland
The Fjerritslev Formation in the Norwegian-Danish Basin forms the main seal to Upper Triassic-Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjael-land, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian-Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry-mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6-10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer-Emmett-Teller (BET)-specific surface-area measurements using Kozeny's formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two-three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot's coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.
Petroleum Geoscience, 2014, Vol 20, Issue 3, p. 257-281