Fracture Characterisation in Shales for Efficient Development

In unconventional hydrocarbon plays, shales can act as a seal, source rock and reservoir. Characterising the geometry and kinematics of natural fracture systems within shales is a critical step in understanding reservoir geomechanics, optimising well plans, and predicting induced seismicity. Efficiency of fluid injection to induce hydraulic fracturing in a low permeability unit is enhanced by successful exploitation of the natural fracture network. However, if numerous extensive fractures are encountered in a well, the injected fluid can dissipate across a larger volume and reduce the tendency for new hydraulic fractures to form or simply bypass large volumes of rock. Whilst natural fractures are useful, the presence of too many long and interconnected fractures can be as problematic as too few natural fractures. A detailed understanding of the fracture network can optimise development plans. Because data from boreholes are inherently sparse and of limited spatial extent, and since fracturing in shales is often predominantly sub-seismic in scale, the use of outcrop based studies is critical to provide sufficiently rich datasets.
Outcrops of Lower Jurassic Whitby Mudstone Fm in north Yorkshire have been analysed to define quantitative characteristics of natural fractures, understand connectivity between fractures, and infer implications for a hypothetical well. Consideration is also given as to what level of fracture characterisation is optimal.
Across an area of ~350m2 of visually homogenous shale a rebound hammer was used as a proxy to infer minor geomechanical variation. Fracture data from lidar, digital photogrammetry and mutually perpendicular 1D structural transects have been acquired from sites within this area.
The interaction between fractures in terms of connectivity and relative timing is evaluated.
A range of spatial and length distributions, and changing dominant orientations of fractures are observed within this area.
A range of length distributions are observed for the earliest of the two dominant fracture sets, some having significantly high proportions of long fractures and few short fractures.
Understanding the range of size, intensity and spacing of natural fractures seen at outcrop can be used to help quantify risk; e.g. to assess the risk of drilling a well that would encounter a suboptimal natural fracture density. To plan an optimal well trajectory, an analogue fracture study which quantifies the range of orientation, interaction, size and spacing of fractures is optimal.