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