Permeability in sedimentary basins is inherently anisotropic across a range of spatial scales (Desbarats 1987; Clennell et al. 1999), where horizontal permeability is often an order of magnitude or more greater than vertical permeability. The average or effective vertical permeability (keff) for flow perpendicular to bedding is approximated as a harmonic mean (Kreitler 1989), where L and k are the thickness and permeability of strata, respectively,
In the layered structure of sedimentary basins, keff will be dominated by the least permeable rock layer, even in cases where there is only a thin low-k layer. For example, if we assume permeability values for shale (10−18 m2) and sandstone (10−15 m2) (Freeze and Cherry 1979) and calculate keff from Equation (1) for a 1000 m thick rock column, of which 20 m are shale and 980 m are sandstone, keff is 5 × 10−17 m2. That is, keff is only 5% of the permeability of sandstone, even though sandstone comprises 98% of the hypothetical section. More commonly, stratigraphy above black shales is dominated by fine-grained rocks (e.g., shales and mudstones) and therefore, multiple, sometimes thick, low-k layers may limit vertical flow rates (Sandberg 1962; Baird and Dyman 1993; Ryder et al. 2008, 2009, 2012). Two examples of shale-dominated overburden are shown in Figure 2. Low keff makes intuitive sense because the rocks must have low permeability in order to have trapped buoyant fluids (i.e., oil and natural gas) over timescales of tens to hundreds of millions of years (Connolly et al., 1990a,1990b; Stueber and Walter 1991; Thornton and Wilson 2007).
Causes of Low Permeability at Depth
The grain-size distribution is the dominant control on permeability, however, other factors are also important at depth, including effective stress, partial saturation, and cementation, often reducing permeability by orders of magnitude.
Permeability is partly dependent on effective stress, which controls the amount of compaction and fracture apertures in a given rock layer. Both the void space and connectivity decrease as effective stress increases, thereby restricting flow and lowering permeability. Kwon et al. (2001) provided a pressure-permeability relationship for the Wilcox Shale based on laboratory experiments, k = k0[1 − (Pe/P1)m]3, where k0 is on the order of 10−17 m2, P1 is 19.3 (±1.6) MPa, m is 0.159 (±0.007), and Pe is the effective stress (Pe = Pc − χPp, where Pc is the overburden stress, Pp is fluid pore pressure, and χ is a constant that is approximately one for shales; Kwon et al. 2001). This relationship is plotted in Figure 3A. Note that the relationship of Kwon et al. (2001) is for horizontal permeability (for flow parallel to bedding), which is typically higher than vertical permeability (for flow perpendicular to bedding). Kwon et al. (2001) indicate that permeability decreases by 4 orders of magnitude as effective stress increases to 12 MPa (e.g., conditions that may be encountered at depths >1000 m).
Figure 3. (A) Normalized permeability of Wilcox Shale from Kwon et al. (2001), assuming that effective stress is the difference between lithostatic pressure and hydrostatic pressure. The bulk density of overburden and water were assumed to be 2300 kg m−3 and 1000 kg m−3, respectively. k0 in this case would be the permeability at the land surface (i.e., when effective stress is zero); (B) relative permeability estimated from Equation (2). k0 in this case would be the permeability for water-saturated rock. In gas-rich shales, pore space is predominantly occupied by gas and oil; therefore, the permeability to water is reduced by orders of magnitude.
Download figure to PowerPoint
The presence of multiple fluid phases (e.g., oil, natural gas, and water) in porous media also reduces permeability. One common relationship for relative permeability (Kr) is given below, where S is saturation and n is a fitted parameter (Brooks and Corey 1964; van Genuchten 1980; Morel-Seytoux et al. 1996),
The relationship between S and Kr for water (from Equation (2)) is depicted in Figure 3B for values of n ranging from 1.5 to 3.5 (for a broad range of grain-size distributions; Bohne et al. 1992). Permeability is sometimes described as being effectively zero if S drops below a critical value, below which the fluid exists as residual water bound to the porous matrix (Pallatt and Thornley 1990). Although permeability is never truly zero, migration of bound water may occur via non-Darcian mechanisms, such as diffusion—a very slow process. Low water saturation is common in source rocks (e.g., black shales) and reservoir rocks, and thus, the permeability of these layers to water is very low. In the Marcellus Shale, for example, natural gas almost fully occupies the available pore space, meaning that water saturation is extremely low and that there is no freely flowing water in the formation (Bruner and Smosna 2011). A number of other gas-bearing layers, such as the Rhinestreet Shale, overlie the Marcellus, and these layers should serve as barriers to vertical flow due to low permeability caused by low water saturation (in addition to other factors discussed in this section). Low permeability strata are also present above other black shales (Sandberg 1962; Kiteley 1978; Swezey 2008), thereby similarly restricting vertical flow in other sedimentary basins.
Cementation (both detrital and diagenetic) is another important process that reduces permeability. Both types of cementation reduce permeability, although diagenetic cement has generally a larger effect (e.g., quartz, calcite precipitation; Panda and Lake 1995). The greatest permeability reduction (often by several orders of magnitude; Archie 1950; Foster 1981 as cited in Bethke 1986; Panda and Lake 1995) is associated with the pore-bridging effect, where cement growth may block pores (Neasham 1977; Panda and Lake 1995). In addition to blocking flow through pore spaces, cement can also block flow through fractures. Cement-filled fractures are a common occurrence in sedimentary basins and can reduce the potential for preferential migration along these pathways (Gale and Holder 2010).
Overall, the preponderance of fine-grained rocks (i.e., shale, siltstone, and mudstone) and the layered structure of sedimentary basins will constrain the vertical permeability of bedrock above black shales toward the low end of measured values. Low permeability layers at depth in sedimentary basins are common, due to the effects of effective stress, cementation, and partial saturation. Only a thin low-k layer is needed to constrain vertical permeability to a low value, however, there are typically many low-k layers present, as are found above the Marcellus, Bakken, and other black shales (Figure 2; Sandberg 1962; Kiteley 1978; Swezey 2008; Ryder et al. 2012). Therefore, it is the rule rather than the exception that vertical permeability in the portions of these basins targeted for oil and gas development is comparable to that of low permeability shales/siltstones/mudstones rather than higher permeability types of rock.