Understanding Net Pay in Tight Gas Sands - A Case Study from the Lower Saxony Basin, NW-Germany

We present an integrated workflow to describe and characterise Upper Carboniferous tight gas sands by systematically integrating core-based macroscopic geologic elements (depositional rock types), microscopic observations (post-depositional diagenesis) and pore-scale properties like capillary pressure and nuclear magnetic resonance data.

Our workflow integrates multiple data sets and scales from a Wintershall-operated tight gas field in the Lower Saxony Basin of Northern Germany. The reservoir is of Westphalian C to Stephanian in age and consists of thick successions of fourth-order coarse- to fine-grained tight sandstone cycles separated by siltstones and in party by anthracite coal seams. The tight sandstones are intensely compacted and cemented with quartz, clay minerals and carbonate cements and generally characterized by low matrix porosities (< 10%) and very low permeabilities (<0.1mD).

A hydraulic rock-typing approach was selected to better define net pay of tight gas sands. In contrast to conventional petrophysical net pay criteria (porosity and water saturation log cut-offs), our approach makes use of the calculated pore throat radius (using Winland R35 equation) and relative permeability measurements (“mobile gas”). Our multi-scale rock typing study enables a better understanding of tight gas sand recovery factors and sweet-spot identification especially for new field development/appraisal projects.