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Mobile Shale Basins – Genesis, Evolution and Hydrocarbon Systems”

June 4-7, 2006 – Port of Spain, Trinidad & Tobago



Role of sedimentation-controlled overpressure development in shale tectonics:  insight from numerical modeling of passive continental margins


Markus Albertz1, Christopher Beaumont1, Steven J. Ings2


1Geodynamics Group, Department of Oceanography, Dalhousie University, Halifax, NS, B3H 4J1, Canada

2Department of Earth Sciences, Dalhousie University, Halifax, NS, B3H 3J5, Canada



            Mobile substrates, such as salt or shale allow passive margins to undergo large-scale gravity-driven gliding and spreading deformation involving updip extension, downdip contraction and compensating translation of the intervening overburden, yielding first-order similarities in structural style.  A variety of structures related to mobile substrates are commonly associated with economically important hydrocarbon deposits encouraging the oil industry to pursue exploration in these areas.  For example, in recent years hydrocarbon exploration has been increasingly focused on the technically and exploratively challenging deep-water contractional domains.  Although major shale tectonic provinces exist around the world (e.g., southern Gulf of Mexico, Caspian Sea, northeastern Venezuela, Beaufort-Mackenzie Delta, and offshore Nigeria), the tectonic development of passive margins whose mobile substrates are primarily composed of shale are relatively poorly understood compared to systems in which salt dominates.  Most shale tectonic studies, however, suggest that sufficiently high levels of pore fluid pressure are a key requirement for shale tectonics, and that high sedimentation rates and associated undercompaction are one mechanism that is directly responsible for generating the necessary levels of overpressure.  However, neither are accurate measurements of pore fluid pressures in productive shale tectonic systems widely available, nor do we understand the dynamic behavior of passive margin scale systems in which the generation and dissipation of fluid overpressures directly control the tectonic evolution.  The purpose of this contribution is to employ forward numerical modeling to investigate the role of sedimentation on overpressure generation thus leading to failure and large-scale deformation of shale and its overburden.  We contrast this deep-seated failure and deformation with the shallow shelf-edge and slope failure and slumping.

            Despite first-order similarities in structural style between salt and shale tectonic systems, major differences in the mechanical properties and rheological behavior between salt and shale suggest that the timing and interplay between sedimentation and the structural evolution of passive margins may differ significantly.  For example, amongst the mechanical properties of salt are:  absence of yield strength, general weakness compared to other rocks during burial, incompressibility, low density, and high thermal expansion.  Hence, salt begins to deform viscously as soon as it is differentially loaded.  In contrast, shale has a finite yield strength which increases with pressure (mean stress) and the density of shale increases with depth under conditions of normal compaction.  However, when pore fluids are present the yield strength depends on the effective pressure Pe (effective pressure equals solid pressure minus pore fluid pressure, Pe = Ps - Pf).  Therefore, the yield strength decreases dramatically with increasing pore fluid pressure (it has been reported, for example, that pore fluid pressures in mobile shale are at least 98% of the lithostatic value), and the rheology can be highly variable depending on what processes generate and dissipate fluid overpressures.  Hence, it is plausible to consider shale a frictional-plastic material when grains are in mutual contact in the undeformed state.  However, increasing pore fluid pressures may lead to yielding and be followed by deformation in which intergrain friction becomes less important as the shale is fluidized and behaves viscously.  In extreme cases, the material may even travel upwards in form of diatremes that erupt at the seafloor as indicated by examples of pock marks and mud volcanoes.  Eventually, dissipation of fluids returns the system to a frictional-plastic behavior, suggesting that frequent rheological changes may occur in shale.  Furthermore, failure and mobilization of shale is not necessarily confined to a stratigraphic horizon but depends on the locations and rates of overpressure generation.

            Based on known material properties, industry reports, and logical reasoning, a simple model for shale rheology can be developed in which shale is frictional-plastic in the undeformed state but behaves viscously during finite deformation when fluid pressures have become sufficiently large to cause failure.  Conceptually, this rheological behavior can be thought of in terms of a frictional block and slider in parallel with a linearly viscous dashpot, and is termed a non-elastic Bingham (visco-) plastic fluid, or Bingham fluid for short.  Prior to failure, the material does not deform owing to the frictional-plastic (block and slider) strength.  Upon yielding the material flows viscously (controlled by the dashpot) such that the shear stress beyond the yield stress is proportional to the shear strain rate.  Bingham fluids are characterized by the Bingham number, B, the ratio of yield to viscous stresses.  In the limit that the yield stress approaches zero the Bingham fluid tends to a Newtonian fluid with B=0.  This approach allows a numerical treatment of the transition from a shale system at rest with strong grain-to-grain contacts to a mobile shale system characterized by post-yield viscous behavior.

            We begin our investigation with analytical theory to explore under which circumstances failure of a basal shale layer induces large-scale deformation of a hypothetical passive continental margin.  The yield strength of the frictional-plastic sediments in our theoretical model strongly depends on f, the internal angle of friction and l, Hubbert and Rubey's (1959) pore fluid pressure ratio.  The pore fluid pressure in the overburden is assumed to be hydrostatic and we take into account the effect of water loading on the seaward side of the model.  We vary the differential thickness, h1 and h2, of the overburden sediments, as well as l in the basal shale layer.  The results from analytical theory are compared with finite element stability test models.  Consistent with published estimates, our results indicate that pore fluid pressures must be extremely large, at least as high as 98% of the lithostatic pressure to induce large-scale failure of the shale and hence deformation of the overburden at the scale of the model margin.  More local failure can occur at somewhat lower values of the pore fluid pressure.  The corresponding post-yielding analytical and numerical model velocities can also be compared.  In addition, the results can be compared with the corresponding ones for stability of overburden above a salt layer.

            The stability test models provide an estimate of the minimum pore fluid pressures required to cause failure and large-scale deformation.  However, in terms of dynamic behavior of natural systems, the circumstances required to develop and sustain high pore fluid pressures for a period of time need to be known.  A relevant example is the Niger Delta, in which highly focused deltaic sedimentation in depocenters is thought to have caused progressive, step-wise outbuilding of the delta.  The stepwise generation and seaward migration of depocenters may be directly linked to sedimentation-controlled pore fluid overpressures and failure of underlying marine shale.  Using the Niger Delta as a natural analog, we employ two-dimensional vertical cross section finite element modeling to test the hypothesis that depocenters in deltas at passive margins experience near lithostatic transient fluid pressures during sediment progradation, ultimately leading to episodic failure of marine shale and associated stepwise seaward propagation of the depocenters.  In the numerical models, the ambient pore fluid pressure ratio, l, in shale at a given location is parametrically modulated by Dl in proportion to the sedimentation rate on the prograding model delta vertically above (Dl = k VS).  This modulation is a maximum when the shale is considered to have a low permeability such that the sediment loading is too fast for normal fluid expulsion and compaction in the shale and leads to increased overpressuring.  No modulation occurs when the shale is considered sufficiently permeable that fluid is expelled, compaction follows a normal trend and pore fluid pressures do not increase.  Furthermore, the finite element models are isostatically balanced to allow for dynamically determined tilt which modifies the geometry and stability of the delta system during its progressive evolution.

            Figure 1A illustrates the initial set-up of the large deformation finite element models.  A 1 km thick visco-plastic marine shale layer (the rheological behavior is represented by a Bingham material; block and slider in parallel with dashpot) is overlain by frictional-plastic sediments (block and slider rheology model).  Prior to the onset of sediment progradation, the landward overburden is 3 km thick and decreases seaward to a thin sediment layer of 10 m over a distance of ca. 200 km.  Figure 1B demonstrates how frictional-plastic sediments prograde in a seaward direction across the marine shale resulting in sigmoidal sediment packages with progressively younger ages.  Note that in this case the value of Dl is too small to induce failure in the shale and deformation of the overburden.  In contrast, Figure 1C illustrates schematically how coupling between sedimentation rate and pore fluid pressure can influence the deformation style at passive margins.  Note that the modeling results vary depending on the choice of input parameters.  Unstable models have the following characteristics: extension, shale withdrawal, and thinning of the shale occur beneath the outer shelf.  In the slope region, contractional deformation and associated thickening of the basal shale layer occur as indicated by fold belts that propagate further downslope with time.  During unstable episodes, the intervening overburden between the extensional and contractional domains translates in a seaward direction.  Despite constant sediment progradation velocity VP, the effect of instability is to create highly focused and episodic sedimentation resulting in stratigraphically distinct depocenters.  Likewise, the downslope fold belts show episodic activity, resulting in overall seaward propagation of the contractional regime.  The results suggest that depocenters in deltas at passive margins can experience near lithostatic transient fluid pressures during sediment progradation, leading to episodic failure of marine shale and associated stepwise seaward propagation of the depocenters as well as the downslope fold belts.  By varying model progradation velocities VP and the coupling between sedimentation and pore fluid pressures, Dl = k VS, we investigate the conditions that lead to situations that match the Niger Delta.  Finite element models allow detailed analysis of the timing relationships between the initiation and completion of individual depocenters and fold belts.
















































Figure 1.  A. Initial set-up and rheological models used in finite element models.  B. Illustration of basinward sediment progradation for models in which pore fluid pressures in marine shale are below the critical value to drive the system towards failure.  C. Schematic representation of deformation style resulting from finite element models in which sedimentation rate and l are parametrically coupled and failure in shale leads to large-scale deformation of the overburden.

AAPG Search and Discovery Article #90057©2006 AAPG/GSTT Hedberg Conference, Port of Spain, Trinidad & Tobago