Advances in horizontal drilling and multistage hydraulic fracturing have made production from low permeability reservoirs possible and economical. Careful measurements of core permeability in shale reservoirs indicate that matrix permeability is in the nano-Darcy range. These permeabilities are too low to support economic flow rates that have been achieved in such reservoirs. Both empirically and theoretically, it can be concluded that production success is due to the multistage hydraulic fracture stimulation, which creates a large number of interconnected micro- and macro-fractures near the horizontal wellbore to support economic production rates. Using this hypothesis, we can simulate the reservoir performance of unconventional shale reservoirs both with single-porosity and dual-porosity mathematical models. In fact, the model parameters can be adjusted to provide an explanation for the decline of the rate exponent in the hyperbolic decline analysis, as we have reported in an earlier paper.
In this paper we present the details of the reservoir modeling philosophy and gridding methodology applied to an abnormally high-pressure, unconventional shale reservoir. Results for single- and dual-porosity models will be presented and compared with the decline curve analysis (DCA) results. Furthermore, the effect of gas condensation in the pores is discussed both from the flow and thermodynamics points of view. It is concluded that much uncertainty exists about the exact nature of flow and production mechanisms in low-permeability shale reservoirs; nonetheless, one can predict future performance with acceptable engineering accuracy and reliability using intrinsically different models.
Oil and gas production from unconventional reservoirs, to include shale oil and shale gas, has contributed significantly to the U.S. domestic energy supplies and is rapidly expanding with continued improvements in horizontal well drilling and hydraulic fracturing techniques. These reservoirs are classified as to whether the hydrocarbon source is an integral part of the reservoir rock fabric (self-sourced, as in Haynesville), or is adjacent to the reservoir (locally sourced, as in Bakken), or is located at large distances from the reservoir and require significant hydrocarbon migration (externally sourced, as in Austin Chalk) (Tepper et al., 2013).
Abnormally high pressure, low permeability and low porosity characteristics are common attributes for most of the shale plays and, more importantly, the reservoir ultimate recovery potential depends on several key parameters: lithology, mineralogy, thermal maturity level, fluid properties, and pore types. A correlation based on permeability, dominant flowing phase and its viscosity is shown on Fig.1 (Bohacs, et al., 2013). The ratio of permeability and viscosity indicates that dry gas, such as Marcellus, can flow at significant rates in nano-darcy rock whereas black oil, such as Bakken, requires relatively higher permeability rocks for economic rates. Specifically, in shale oil reservoirs, existence of relatively larger inter-and intra-granular pores and pore throats and fracture porosity provides sufficient ease of mobility to oil to generate economic well flow rates. In contrast, the flow of gas in smaller diameter pores, existing within the kerogen in shale gas reservoirs, as in Barnett, is facilitated by a favorable thermodynamic phase envelop shift and Knudsen flow (Pang, et al., 2012).
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