Several authors have demonstrated the use of coupled geomechanical simulations to explain changes in traveltimes derived from time-lapse seismic surveys over compacting reservoirs (see Hatchell et al., 2003; Sayers, 2004; Hatchell and Bourne, 2005; Herwanger et al. 2007; Janssen et al., 2007; Kosco et al, 2010; Herwanger et al., 2013). Under this same concept, we have employed large-scale geomechanical simulations to translate reservoir depletion values into rock deformations and subsurface velocity changes. We apply this methodology to channelized turbidite complexes of the Dalia field, located in Block 17, offshore West Africa, aiming to generate a geomechanically derived overburden time-shift model and validate predicted signatures against an actual 4D seismic monitor survey. Our results are able to replicate both slow-down and speedups in the vicinity of depleted sand bodies, following patterns consistent with stress-arching effects in the overburden.
Geomechanical Modeling of Overburden Behavior
Full-field geomechanical models have been previously employed in the Dalia field to successfully address infill issues (see Onaisi, 2014; Pourpak et al., 2014; Onaisi et al., 2015). Building on this experience, this paper explores the notion of how geomechanical models can assist in explaining production-induced time-lapse seismic signatures. Because reservoir seismic velocity changes are also strongly affected by saturation changes, most of the scope of this paper is limited to the overburden immediately overlying the reservoir.
The Dalia field, located in Block 17, offshore West Africa, is characterized by four main sedimentary complexes, called Upper Main Channel, Lower Main Channel, Lower Flanks, and Camelia. The reservoirs are of Lower Miocene age, consisting of unconsolidated sandy turbiditic deposits. Depositional and erosional geometries, along with sedimentary facies distribution, affect fluid flow by a complex network of preferential pathways (Pluchery et al., 2013). The reservoir layers lie not very far (about 800 m) below the seabed, forming unconsolidated and heterogeneous oil reservoirs (see Prat el al., 2010; Pluchery et al., 2013). This area is also characterized by high-resolution seismic data (down to 10 m) that is used for fine reservoir characterization and monitoring (Gonzalez-Carballo, et al., 2006; Vemba, et al., 2011). As described by Onaisi et al. (2015), a geomechanical model was constructed based on seismic inversion data, representing present-day conditions throughout the reservoir and its surroundings. For such purposes, we used a finite element geomechanical modeling engine (Koutsabeloulis and Hope, 1998) to produce a 3D map of stress and strain magnitudes and orientations that vary both laterally and vertically. The model uses pore pressures from a reservoir simulator, structure, rock mechanical properties, and far-field horizontal stresses imposed as boundary conditions to simulate the initial stress state of the field, calibrated with well measurements and with drilling experience.