Subsurface Mapping Of Natural Fracture Networks; A Major Challenge To Be Solved. Case Study From The Shale Intervals In The Cooper Basin, South Australia.

Abstract

The future success of both enhanced (engineered) geothermal systems and shale gas production relies significantly on the development of reservoir stimulation strategies that suit the local stress and mechanical conditions of the prospects. The orientation and nature of the in-situ stress field and pre-existing natural fracture networks in the reservoir are amongst the critical parameters controlling the success of any stimulation program. This work follows an initial study showing the existence of natural fractures in the area covered by the Moomba–Big Lake 3D seismic survey, in the South-Western termination of the Nappamerri Trough of the Cooper Basin in South Australia. The fractures, imaged both by borehole image logs and seismic attributes (including Most Positive Curvature, Ant tracking of Dip Deviation, and Variance), are pervasive across the seismic survey, and present a relatively constant NW-SE orientation. The density of the fractures, as visible on horizon extractions of attributes, is however spatially variable. A high density of fractures is found in the vicinity of the fault planes and tight antiforms. We compare apparent fractures from different seismic attributes (seismic fractures) with faults interpreted from well data and on vertical seismic sections. Results indicate that some seismic fractures are small faults with small offsets up to 3 ms. Other seismic fractures are actual fractures striking parallel to nearby faults. Analysis shows that under present day stress orientation and magnitudes, fractures striking NW-SE and NE-SW are more susceptible to stimulation, and are more likely to open for fluid flow.