Aderson F. do Nascimento

Crustal structure of the eastern Borborema Province, NE Brazil, from the joint inversion of receiver functions and surface wave dispersion: Implications for plateau uplift

We investigate the crustal structure of the Borborema Province of NE Brazil by developing 44 S wave velocity-depth profiles from the joint inversion of receiver functions and fundamental mode, Rayleigh wave group velocities. The Borborema Province is located in the northeasternmost corner of the South American continent and represents a portion of a larger Neoproterozoic mobile belt that formed during the Brasiliano-Pan African orogeny. Extensional processes in the Mesozoic—eventually leading to the separation of Africa and South America—left a number of aborted rift basins in the continental interiors, and episodes of diffuse intraplate volcanism and uplift marked the evolution of the Province after continental breakup. Our velocity-depth profiles reveal the existence of two crustal types in the Province: (i) the thin crustal type, which consists of 30–32.5 km thick crust, with an upper layer of 3.4–3.6 km/s overlying a lower layer of 3.7–3.8 km/s and (ii) the thick crustal type, which consists of a 35–37.5 km thick crust, with velocities between 3.5 and 3.9 km/s down to ∼30 km depth and a gradational increase in velocity (VS≥4.0 km/s) down to upper mantle depths. The crustal types correlate well with topography, with the thick crustal type being mainly found in the high-standing southern Borborema Plateau and the thin crustal type being mostly found in the low-lying Sertaneja depression and coastal cuestas. Interestingly, the thin crustal type is also observed under the elevated topography of the northern Plateau. We argue that the thick crustal type is rheologically strong and not necessarily related to postbreakup mantle processes, as it is commonly believed. We propose that extensional processes in the Mesozoic stretched portions of the Brasiliano crust and formed the thin crustal type that is now observed in the regions of low-lying topography, leaving the rheologically strong thick crust of the southern Plateau at higher elevations. The crust making the northern Plateau would have thinned and subsided during Mesozoic extension as part of a greater Sertaneja depression, to then experience uplift in the Cenozoic and achieve its present elevation.

Seismogenic faulting in the Meruoca granite, NE Brazil, consistent with a local weak fracture zone

A sequence of earthquakes occurred in 2008 in the Meruoca granitic pluton, located in the northwestern part of the Borborema Province, NE Brazil. A seismological study defined the seismic activity occurring along the seismically-defined Riacho Fundo fault, a 081° striking, 8 km deep structure. The objective of this study was to analyze the correlation between this seismic activity and geological structures in the Meruoca granite. We carried out geological mapping in the epicentral area, analyzed the mineralogy of fault rocks, and compared the seismically-defined Riacho Fundo fault with geological data. We concluded that the seismically-defined fault coincides with ∼E-W-striking faults observed at outcrop scale and a swarm of Mesozoic basalt dikes. We propose that seismicity reactivated brittle structures in the Meruoca granite. Our study highlights the importance of geological mapping and mineralogical analysis in order to establish the relationships between geological structures and seismicity at a given area.

Spatial pressure compartmentalization in faulted reservoirs as a consequence of fault connectivity: a fluid flow modelling perspective, Xaréu oil field, NE Brazil

Sealing faults may have a major impact on reservoir compartmentalization and play a key role in advanced oil recovery strategies. Because of the different approaches and scales used to characterize faults, a considerable gap remains between engineers’ and geologists’ conceptions of faulted reservoirs. The fundamental difficulty in integrating these views lies in constructing realistic reservoir-scale models incorporating relevant fault properties on several scales, so that fault connectivity and its impact on fluid flow can be simulated and quantified properly. This paper is a step towards examining quantitatively the impact of fault connectivity on fluid flow at a reservoir scale. A stochastic reservoir model incorporating sealing faults was constructed. The number of faults in the model were gradually increased and several fluid flow simulations performed in order to verify the impact of fault density and fault connectivity on the spatial pressure variation. Despite being synthetic, the model incorporates some properties of an actual carbonate reservoir, the Xaréu oil field (XOF) in the Ceará Basin, NE Brazil. In the XOF, thin (<15 m) oil-bearing carbonate layers are interlayered in a thick (>50 m) shale bed. Sealing effects may be caused by the faults because they usually have a normal slip component, so that the thick shale layer becomes juxtaposed against the thin carbonate layers, behaving as barriers to fluid flow in the carbonate layers. It appears that there is no reservoir compartmentalization in the carbonate layers because there is overall pressure depletion in XOF – all the new wells drilled in the carbonate layers, before starting production, showed formation pressure values smaller than the formation pressure measured in the first wells drilled in the field. Nevertheless, it was not understood how such communication throughout the entire reservoir (approx. 19 km2) could occur, given the presence of laterally extensive faults, with up to 5 km in strike and maximum vertical displacement greater than the reservoir thickness. In the synthetic model, fault population follows a displacement-length property derived from seismic data. Sub-seismic faults were also incorporated in the model using a downscaling law. The location, direction and length of each fault were also generated stochastically. In order to quantify the ‘degree of faulting’, two criteria were used: fault density (the fractions ‘total fault length per occurrence area’; f1) and fault connectivity (the fractions ‘number of fault intercepts per occurrence area’; f2). By comparing f1 and f2 for the real and simulated versions of the XOF carbonate reservoir it is concluded that the carbonate layers remain interconnected so that compartmentalization does not exist. From a methodological viewpoint, the most important aspect of the modelling is the change of focus regarding sealing. At least for the purposes of investigating interconnection, the adequate focus is on the ‘percolation core’ of the reservoir (its hydraulically connected and undamaged parts) and not on the faults themselves, regardless of their sealing nature.

Investigating the relationship between fault permeability and effective stress using constraints from reservoir induced seismicity (ris)

Abstract This research uses observations of RIS beneath Acu Reservoir, NE Brazil, to investigate the damage zone permeability of geological faults. High-resolution digital seismic monitoring of the reservoir has provided detailed information on the locations of seismic events. The temporal distribution of these events shows them to be directly related to annual fluctuations in the reservoir level. Model simulations, using a decoupled hydromechanical formulation (i.e. a static permeability field decreasing exponentially over depth due to increased confining pressure), show that for pressure-diffusion to be a hydrogeologically consistent mechanism for RIS, preferential flow must occur within 2D fault planes embedded in a 3D low permeability matrix. Further, the observed spatial and temporal variability of earthquakes indicate that these faults must have heterogeneous permeability fields with significant spatial structure; pockets of high and low permeability of the order of 0.5 – 1.5 km in diameter. Predictions of the maximum pressure change in these faults at hypocentral depths indicate

Trade-off between stability and bias in a history match problem using smoothness constraint

The history matching (HM) hydrocarbon reservoir inverse problem is ill-posed because its solution may be non-unique or unstable. Variability of acceptable solutions around local minima may be very large. Nonetheless, it is a common practice in HM to find a unique reservoir model, although there is no guarantee that this model represents the geology. Qualitative geological information is generally not considered because of difficulties to express them mathematically. Here, we incorporate ‘smoothness’ in the spatial variation of physical properties as an example of a geological qualitative constraint that can be mathematically incorporated in an objective function also honouring the data. The constraint is valid if lateral continuity exists (e.g. fluvial-deltaic siliciclastic reservoirs). We mean smoothness by conditioning the permeability and/or porosity difference between adjacent grid blocks to be small. We use a synthetic 2D water–oil model and a solution search technique allowing characterising both the optimum solution and its variability. The smoothness constraint reduces the variance of the estimates by introducing bias in the solutions still preserving good match. The key point to achieve an optimum trade-off between stability and data match is the tuning of the parameter, controlling the relative importance of the constraint in the objective function. The smoothness constraint cannot be applied to all reservoirs. However, we corroborate the idea that a ‘tool box’ of HM can be designed; each ‘tool’ can incorporate a different constraint. Therefore, the interpreter can judiciously choose a specific tool from this tool box according to the adherence of its constraint to the particular reservoir being studied.

History match of a real-scale petroleum reservoir model using smoothness constraint

The history match procedure in an oil reservoir is of paramount importance because good estimates of the reservoir parameters may lead to a better forecast of the production. The reservoir is said to be ‘matched’ when the discrepancies between the model predictions and the observations of the real reservoir are below a certain tolerance. The determination of the model parameters via history matching requires the minimisation of an objective function in a parameter space that may be populated by many local minima. In other words, more than one set of reservoir model parameters fits the observation. Moreover, even a solution associated to a given minimum may be unstable. In order to reduce the ambiguity, it is necessary to incorporate constraints in the reservoir parameters to be estimated. Here, we use the smoothness constraint to regularise this inverse problem using as an example a modified version of the PUNQ model. The PUNQ model is suitable for applying this constraint because the sediments were deposited in a deltaic costal plain environment where good lateral continuity of the sediments is expected. We show that it is possible to recover all important features of the spatial distribution of the permo-porosity fields in all layers of the PUNQ model. In particular, the directions and widths of the sand channels were recovered.