Reservoir evaluation of shaly formations and enhancement of reservoir characterization has long been a difficult task. This study is devoted to developing relationships for interpreting the combined effects of subsurface stress and shale on petrophysical properties of reservoir rocks. These new relationships are used to: (1) identify shale types, (2) characterize flow units in shaly formations using in situ measurements, and (3) study the effect of stress on reservoir quality index and fluid flow paths of shaly formations.
Several flow unit models have been developed to achieve these goals. The proposed flow unit models are based on current shale models appearing in the literature. These flow unit models introduce unique parameters for reservoir characterization of shaly formations. These parameters include the slope of a traight line (that defines the flow unit) and the stress factor on a log-log plot of in situ reservoir quality index versus in situ porosity of the shaly formations. Finally, these models are used to identify shale types and select a suitable water saturation model for shaly formations.
The models are validated using simulated data of porosity and pressure. The new models, in combination with the methodologies developed in this study, represent an effective tool for an enhanced reservoir description of shaly reservoirs.
Characterization of shaly formations has been a difficult task for several reasons. One key factor of this difficulty is that the use of conventional core test data simply does not work. Special equipment or procedures are required to determine the low permeabilities and porosities. A serious, and more fundamental, problem related to studying shaly formations is that of the very heterogeneous nature of shales. In addition, the consideration of the subsurface stress effect will make investigation and characterization of shaly formations much more difficult. With respect to the stress effect, Hilchie(1) used six brine saturated porous samples under simulated conditions of overburden and temperature. The simulated overburden pressure used was up to 68.45 mPa (10,000 psi) and the simulated temperature conditions were up to 232 °CDATA[C (450 °CDATA[F). The results showed that the increase of stress caused an increase of the formation resistivity factor.
Longeron(2) investigated the effect of overburden pressure on the electrical properties of sandstone. The results showed that the formation resistivity factor increased by about 15﹪ for sandstone when stress ranging from 276 mPa to 20 mPa (400 psi to 2,900 psi) was applied. Lewis et al.(3) investigated the effects of stress and wettability on the water saturation exponent "n" and the cementation exponent "m." The results showed that changes in stress have a relatively minor effect upon the water saturation exponent "n" and the cementation exponent "m," but trends having an increase in these exponents with increasing stress levels have been observed. Lewis et al. data also showed a slight decrease in these exponents with decreasing stress, but the effectf stress on the water saturation exponent "n"was less clear than that of the cementation exponent "m."Therefore, changes in the cementation and water saturation exponents are probably small enough that they can be neglected.