Baker Hughes is publishing a book titled Unconventional Resources: Exploitation and Development covering a wide variety of topics central to optimizing recovery and profitability of these reservoirs. This blog entry includes extracts from the book which will be available at http://www.shopbakerhughes.com/
In our last blog post we looked at the various flow mechanisms potentially associated with ultra-low permeability reservoirs.
Conventional models of porous media incorporate the concept of a representative elementary volume (REV). This volume has aggregate properties (porosity, permeability, saturations) representative of a larger volume. Even in very heterogeneous porous media, the REV concept is useful. For example, the REV of a naturally fractured reservoir might be relatively large; however, the media can be described as a composite reservoir comprising unfractured matrix and fractures. The REV sizes of the component media may be quite small. Tight gas and conventional models assume that the bulk of all hydrocarbon storage is in matrix pores. Flow only occurs as interconnected pores communicate pressure changes initiated at wellbores. In the conventional/tight gas models hydraulic fractures provide large surface area that more effectively communicate pressure changes to the reservoir but do not significantly affect the bulk properties of the matrix.
The created hydraulic fractures in unconventional wells can increase bulk matrix permeability. This can be the result of shear slippage of previously closed natural fractures, slowly slipping faults and other factors. This is a somewhat controversial topic and some experts do not believe that improving matrix permeability is necessary if created hydraulic fractures have sufficient surface area. Others strongly disagree and insist that unconventional reservoirs cannot be successful without this fracture-rock interaction. The truth is probably a complex amalgam of the two opinions. Additionally, storage of hydrocarbons in organic matter or adsorbed onto the matrix may be significant relative to those stored in pore spaces.
Figure 1 Gas evolution and transport at different scales in shales (Javadpour, 2007)
Javadpour described multiple scales for fluid flow. Figure 1 illustrates gas evolution and transport mechanism in shale formations at different scales. The differences in flow models for the smallest pores may incorporate different models for wall slip, the relative size of the molecules and the pore-throats, the mean free path of the molecule and chemical and physical interactions with pore surfaces. The Knudsen number is useful in describing flow regimes and is defined as K_n where d is the pore-throat diameter and λ is defined as:
k_b is the Boltzmann constant, 1.3806488 × 10-23 m2 kg s-2 K-1,
T is the temperature (K).
P is pressure, atm,
σ is the particle hard shell diameter
The Knudsen number is a function of temperature and pressure (Figure 2). Values below 0.001 correspond to no-slip (D’arcy) flow. Values of Kn between 0.001 and 0.1 correspond to slip flow or Knudsen diffusion. Javadpour illustrates these flow regimes for different pore-throat sizes. They then describe an alternative approach applicable for constant diffusion coefficient flow with minimal viscous effects. Their measurements indicate that nanopores dominate flow behavior in many shale core samples.
Figure 2 Knudsen number for a gas mixture for different pore sizes
Nelson provides an interesting comparison of porosity, permeability and pore-throat sizes in sandstones, tight sandstones and shales (Figure 3). The contrast in pore-throat sizes going from conventional to tight to shales is truly remarkable. The extraordinarily small pore-throat sizes suggest that some level of natural fractures may be necessary to improve the bulk permeability and that even very low fracture conductivities can substantially enhance fluid flow.
Figure 3 Pore-throat sizes in sandstones, tight sandstones and shales (Nelson, 2009)