Types and Causes of Induced Seismicity - Induced Seismicity Potential in Energy Technologies - page 27

pressure propagates in a saturated rock; like the permeability ( k ), the diffusivity ( c ) can vary
over many orders of magnitude for different rocks. These parameters can be determined
either from laboratory tests on drill core samples from wells or from pumping or injection
tests, which have the advantage of providing estimates that are averaged over a scale relevant
for reservoir calculations.
The intrinsic permeability of basement rocks is so low that the transport of fluid in these
rocks can be thought of as taking place almost exclusively in the network of fractures that
is pervading the crust. In other words, the rock itself can be viewed as being impermeable.
Concepts of permeability and storage coefficient can be extended to fractures, where they
transform into a transmissivity and storativity, with their ratio also having the meaning of
diffusivity (see, e.g., Nicholson and Wesson, 1990; NRC, 1996).
The important point is that faults and fractures in basement rocks offer relatively little
resistance to flow, and thus the equivalent permeability and diffusivity of these fractured
rocks (with fractures and rocks viewed as a whole) can be very high. For example, the
hydraulic diffusivity deduced from the time evolution of spatial spread of microseismic
events measured during injection of water into a crystalline rock at Fenton Hill, an EGS
site (Fehler et al., 1998), is about 0.17 m 2 is (Shapiro et al., 2003), a value in the range of
those for very permeable sandstones. The combination of high transmissivity, small stor-
ativity, and the planar nature of fractures implies that significant pore pressure changes can
be transmitted over considerable distances (several kilometers [miles]) through a fracture
network from an injection well.
In permeable rocks, where the fluid is dominantly transported by a connected network
of pores, the injection of fluid from a well can be viewed as giving rise to an expanding
“bulb,” centered on the well, which represents the region where the pore pressure has in-
creased. The increase in pore pressure decreases with distance from the well until it becomes
about equal to the initial pore pressure, prior to injection, at the edge of this expanding
region. Once the size of this bulb becomes larger than the thickness of the permeable layer,
the shape of this region becomes approximately cylindrical over the height of the layer. The
region of perturbed pore pressure continues to grow radially until it meets bulbs growing
from other injection wells or until it reaches the lateral boundaries of the reservoir (see also
Nicholson and Wesson, 1990).
The dependence of the magnitude of induced pore pressure and of the size of the per-
turbed pore pressure region on the injection rate, the volume of fluid injected, and the rock
hydraulic properties (permeability and storage coefficient) is complex. Numerical simula-
tions are generally needed to establish these relationships, which depend on the geometry
of the permeable rock. However, some general rules apply either at the early stage of injec-
tion when the bulb of increased pore pressure grows unimpeded by the interaction with the
lateral boundaries of the reservoir or with other bulbs, or at a late stage of injection when
the increase of the pore pressure is nearly uniform in the reservoir, which is here assumed