We systematically describe an approach to estimate the large‐scale permeability of reservoirs using seismic emission (microseismicity) induced by fluid injection. We call this approach seismicity‐based reservoir characterization (SBRC). A simple variant of the approach is based on the hypothesis that the triggering front of hydraulically‐induced microseismicity propagates like a diffusive process (pore pressure relaxation) in an effective homogeneous anisotropic poroelastic fluid‐saturated medium. The permeability tensor of this effective medium is the permeability tensor upscaled to the characteristic size of the seismically active heterogeneous rock volume. We show that in a homogeneous medium the surface of the seismicity triggering front has the same form as the group‐velocity surface of thelow‐frequency anisotropic, second‐type Biots wave describing kinematic aspects of triggering‐front propagation in a way similar to the eikonal equation for seismic wavefronts. In the case of isotropic heterogeneous media, the inversion for the hydraulic properties of rocks follows from a direct application of this equation. In the case of an anisotropic heterogeneous medium, only the magnitude of a global effective permeability tensor can be mapped in a 3‐D spatial domain. We demonstrate the method on several field examples and also test the eikonal equation‐based inversion.

We consider various cases of seismicity, induced by artificial fluid injections in boreholes. Like many other authors, we support the hypothesis that to a large extent the triggering of this seismicity is caused by a diffusive process of the pore pressure relaxation in porous (or fractured), saturated rocks. We show that if this hypothesis is correct, then the spatio-temporal distributions of the seismic events must have several specific features related to the effective permeability of the rock. As a rule the fluid injectioninduced seismicity obeys such features. These features can be indications of the diffusive and even hydraulic nature of the seismicity triggering process.From this point of view we analyze the spatio-temporal distribution of the late aftershocks of the Antofagasta (northern Chile) 1995 earthquake. These aftershocks were concentrated in a plane, an approximately 3 km-thick spatial zone. This thin seismogenic layer is a part of the South American subduction zone. The time-distance distribution of the aftershocks along this layer indicates that they could be triggered by a diffusion-like process. Possibly, such a process is the relaxation of the pressure perturbation caused in the pore fluid by the main Antofagasta event. We estimated the permeability required to explain the spatio-temporal distribution of the aftershocks by such a triggering mechanism. The obtained value, 60 mD, is very large. However, it is realistic for a long-time existing and large-scale fault zone.

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The Longtom gas field was discovered in 1995, when the Longtom–1/ST1 wildcat well in the northern part of the offshore Gippsland Basin encountered dry gas in tight sandstones towards the base of the Latrobe Group, in what is now called the Admiral Formation of the Emperor Subgroup. In 2004 the Longtom–2/ST1 exploration well confirmed significant vertical and lateral extension of these prospective gas sands, and also provided very encouraging production test and core data. The recent Longtom–3 wells have demonstrated the viability of this new play by confirming significant lateral continuity of the thicker gas sands and demonstrating high gas flow rates. The history of the field’s discovery and appraisal illustrates how a multi-disciplinary and interactive approach, guided by innovative seismic inversion techniques and real-time petrophysical data, resulted in the successful planning and execution of the Longtom–3 drilling and evaluation program. The results of the wells and the outline of the field development plan illustrate how Longtom represents new production potential in this mature basin.