Fluids and Rocks - Introduction to Carbon Capture and Sequestration - page 415

10000

1000

100

10

1

0.1

0.01

0.001

0.00 0.05 0.10 0.15 0.20 0.25 0.30

Porosity

Figure 9.6.1 Relation between permeability and porosity
Permeability (md) as a function of porosity (%) for thousands of core samples from the
St. Peter sandstone in Illinois. Figure based on Leetaru et al. [9.21] .

where N is the number of fractures per meter, and b is the fracture
aperture. For example, one fracture with thickness equal to that of a sheet
of paper across 10 m is equivalent to a permeability of k 0.1 m − 1

= ×

(1 x 10 − 4 m) 3 /12 10 − 15 m 2 = 8 × = 8 md, which is is approximately equivalent

to the overall permeability of silt.
Fracturing can be caused by pressure from the CO 2 injection.
Figure 9.6.3 shows various pressure profi les in the subsurface relevant
to fl uid injection. The hydrostatic pressure profi le is determined by gravity
acting on fl uid in the connected pore space of the geological system.
Assuming continuous pore connectivity and equilibrium conditions, pres-
sure increases with depth as a function of fl uid density. At these condi-
tions, the pressure inside the pores is typically very nearly hydrostatic. In
order to inject fl uid into a subsurface formation, the injection pressure
must be larger than the local pore pressure. The curve on the far right-
hand side of Figure 9.6.3 is the lithostatic gradient . This pressure arises
from the weight of the rock itself, and is a function of total rock density
and depth. If the fl uid injection pressure exceeds the lithostatic pressure,
the rock will open up along horizontal planes and lift the rock column to
form a cavity or void space (see also Question 9.6.1 ).