Geological and petrophysical parameters limiting the productivity of low-permeability formations
The aim of the project was to test the hypothesis of mechanical formation damage effects in the direct vicinity of hydraulic fractures in tight gas reservoirs. Near-fracture stress conditions may provoke a local exceedance of the rocks’s dilatancy boundary. The induced microfractures potentially cause a mobilisation of fines contained in the pores, leading to a permeability reduction. In hydraulic fracture stimulations, the discharge of fines from reservoir rocks at deviatoric stress conditions has been observed, confirming the theory of fines entrainment.
The methods comprised the characterisation of core samples from low permeable gas bearing sandstones of Northern Germany (Upper Rotliegend, Upper Carboniferous, Buntsandstein) with emphasis on properties of potential relevance for damage. Two experimental approaches were conducted, including the experimental simulation of near-fracture stress conditions with a triaxial permeameter and the visualisation of dilatancy effects affecting pore-lining and pore-filling clay minerals by means of dilatancy experiments on small specimens inside an ESEM.
The experimental results show that the analysed tight gas reservoir rocks tend to suffer a permeability loss of up to 30% when subjected to near-fracture stress conditions. Sandstones with a predominance of mechanically instable clay mineral cements seem to be more sensitive than others. The degree of permeability reduction furthermore depends on the degree of maximum strain. A fines discharge, as a result of deviatoric stress, was observed. ESEM observations suggest a dependence of the potential fines entrainment on clay mineral morphology and rheological properties of the sandstones. A mechanical skin zone close to hydraulic fractures in tight gas reservoirs is likely to form, depending on the lithological properties of the reservoir.