Fluid Flow in a Fractured Reservoir Using a Geomechanically Constrained Fault-Zone-Damage Model for Reservoir Simulation

Summary Secondary fractures and faults associated with reservoir-scale faults affect both permeability and permeability anisotropy and hence play an important role in controlling the production behavior of a faulted reservoir. It is well known from geologic studies that there is a concentration of secondary fractures and faults in damage zones adjacent to large faults. Because there are usually inadequate data to fully incorporate damage-zone fractures and faults into reservoir-simulation models, this study uses the principles of dynamic rupture propagation from earthquake seismology to predict the nature of fractured/damage zones associated with reservoir-scale faults. We include geomechanical constraints in our reservoir model and propose a generalized workflow to incorporate damage zones into reservoir-simulation models more routinely. The model we propose calculates the extent of the damage zone along the fault plane by estimating the volume of rock brought to failure by the stress perturbation associated with dynamic-rupture propagation. We apply this method to a real reservoir using both field- and well-scale observations. At the rupture front, damage intensity gradually decreases as we move away from the rupture front or fault plane. In the studied reservoir, the secondary-failure planes in the damage zone are high-angle normal faults striking subparallel to the parent fault, which may affect the permeability of the reservoir in both horizontal and vertical directions. We calibrate our modeling with both outcrop and well observations from a number of studies. We show that dynamic-rupture propagation gives a reasonable first-order approximation of damage zones in terms of permeability and permeability anisotropy in order to be incorporated into reservoir simulators. Introduction Fractures and faults in reservoirs present both problems and opportunities for exploration and production. The heterogeneity and complexity of fluid-flow paths in fractured rocks make it difficult to predict how to produce a fractured reservoir optimally. It is usually not possible to fully define the geometry of the fractures and faults controlling flow, and it is difficult to integrate data from markedly different scales (i.e., seismic, well log, core) into reservoir-simulation models. A number of studies in hydrogeology and the petroleum industry have dealt with modeling fractured reservoirs (Martel and Peterson 1991; Lee et al. 2001; Long and Billaux 1987; Gringarten 1996; Matthäi et al. 2007). Various methodologies, both deterministic and stochastic, have been developed to model the effects of reservoir heterogeneity on hydrocarbon flow and recovery. The work by Smart et al. (2001), Oda (1985, 1986), Maerten et al. (2002), Bourne and Willemse (2001), and Brown and Bruhn (1998) quantifies the stress sensitivity of fractured reservoirs. Several studies (Barton et al. 1995; Townend and Zoback 2000; Wiprut and Zoback 2000) that include fracture characterizations from wellbore images and fluid conductivity from the temperature and the production logs indicate fluid flow from critically stressed fractures. Additional studies emphasize the importance and challenges of coupling geomechanics in reservoir fluid flow (Chen and Teufel 2000; Couples et al. 2003; Bourne et al. 2000). These studies found that a variety of geomechanical factors may be very significant in some of the fractured reservoirs. Secondary fractures and faults associated with large-scale faults also appear to be quite important in controlling the permeability of some reservoirs. Densely concentrated secondary fractures and faults near large faults are often referred to as damage zones, which are created at various stages of fault evolution: before faulting (Aydin and Johnson 1978; Lyakhovsky et al. 1997; Nanjo et al. 2005), during fault growth (Chinnery 1966; Cowie and Scholz 1992; Anders and Wiltschko 1994; Vermily and Scholz 1998; Pollard and Segall 1987; Reches and Lockner 1994), and during the earthquake slip events (Freund 1974; Suppe 1984; Chester and Logan 1986) along the existing faults. Lockner et al. (1992) and Vermilye and Scholz (1998) show that the damage zones from the prefaulting stage are very narrow and can be ignored for reservoir-scale faults. The damage zone formed during fault growth can be modeled using dynamic rupture propagation along a fault plane (Madariaga 1976; Kostov 1964; Virieux and Madariaga 1982; Harris and Day 1997). Damage zones caused by slip on existing faults are important, especially when faults are active in present-day stress conditions because slip creates splay fractures at the tips of the fault and extends the damage zone created during the fault-growth stage (Collettini and Sibson 2001; Faulkner et al. 2006; Lockner and Byerlee 1993; Davatzes and Aydin 2003; Myers and Aydin 2004). In this paper, we first introduce a reservoir in which there appears to be significant permeability anisotropy associated with flow parallel to large reservoir-scale faults. Next, we build a geomechanical model of the field and then discuss the relationship between fluid flow and geomechanics at well-scale fracture and fault systems. To consider what happens in the reservoir at larger scale, we use dynamic rupture modeling to theoretically predict the size and extent of damage zones associated with the reservoir-scale faults.