Understanding the Controls on Fracturing in Shale Basins: Natural Fractures in Lower Jurassic Shales, Cleveland Basin, UK

The Toarcian Whitby Mudstone Formation (WMF), Cleveland Basin, UK, comprises 105m grey and black shales. The mean total organic carbon (TOC) is 3%, locally increasing to nearly 20%. The WMF underwent subsidence during the Mesozoic, reaching the oil window during the Late Cretaceous. It was then cooled and uplifted during Tertiary inversion. Coastal exposures make the WMF an excellent natural laboratory to investigate controls on fracturing in mature, shale-dominated successions. We have identified three distinct structural styles within the WMF.
(1) Regularly spaced, sub-vertical extension fractures with large height-spacing ratios and thin calcite fills. These fractures occur away from tectonic faults, but opened parallel to the regional extension direction and are interpreted as as tensile hydraulic fractures that developed under conditions of low differential stress and vertical maximum principal stress (S1).
(2) Regularly spaced arrays of moderately dipping shear fractures and sub-vertical extension fractures that display mutual cross-cutting relationships. These fractures occur in the footwalls of tectonic normal faults and accommodated E-directed extension. Sub-vertical fractures contain calcite fills; shear fractures contain brecciated shale, but calcite is rare. We interpret these structures as shear and tensile hydraulic fractures that developed under conditions of vertical S1 and fluctuating differential stress and fluid overpressure.
(3) Regularly spaced arrays of sub-horizontal and sub-vertical fractures, which contain bitumen and drusy calcite, and are associated with faults that display dip- and strike-parallel slickenlines. Sub-vertical fractures consistently abut sub-horizontal fractures, implying that S1 flipped from horizontal to vertical. The most parsimonious explanation is that the fractures developed under high fluid overpressures and low differential stresses at the onset of basin inversion. Poroelastic effects caused the horizontal stress to decrease in proportion to the fluid pressure, allowing reorientation of the stress field. These observations suggest that spatial and temporal variations in fluid overpressure under conditions of low differential stress are the main controls on the style and orientation of natural fractures in shale-rich basins. Compositional variations (TOC) had a second-order influence. These findings may have implications for effective utilisation of natural fracture arrays during shale gas production.

AAPG Search and Discovery Article #90142 © 2012 AAPG Annual Convention and Exhibition, April 22-25, 2012, Long Beach, California