Natural fractures conduct fluids in subsurface reservoirs. Quick and realistic predictions of the fracture network organization and its fluid flow efficiency from limited amount of data is critical to optimize resources productivity. We recently developed a method based on multiple point statistics (MPS) technique to produce geologically-constrained fracture network simulations. The method allows to account for the intrinsic non-stationarity of these networks by considering a multivariate input data instead of averaged distribution of fracture parameters. In addition, the method considers probability maps reflecting the influence of fracture drivers in the network variability. Consequently, the simulated fracture networks derived from the innovative MPS approach are geologically better constrained than in classical discrete fracture network modelling approaches. This paper proposes to apply this method in subsurface conditions where available data are sparsely distributed. We developed a workflow where data are gathered from wellbore and from additional sources (outcrops). These data are used to extrapolate a network around the borehole as training images and themselves are extrapolated at the reservoir scale following a geological probability map.This work also presents innovations on the way how training images and probability maps that may integrate more geology constrain than relying almost entirely on available data.@en

The sedimentary succession exposed in the Northern Dalmatia Islands mainly consists of Cretaceous to Neogene shallow water carbonates, folded and imbricated within the External Dinarides thrust belt. During Cretaceous times, carbonate sediments were deposed on a heterogeneous, tectonically-influenced carbonate platform, which was then uplifted and eroded, as evidenced by a regional unconformity embracing the Late Cretaceous and Paleocene. Sedimentation resumed during the Eocene, when the area was part of the foreland basin of the Dinaric belt. With our geological and structural map of the southeastern Pag Island at the 1:25,000 scale, we refined the stratigraphic and structural setting and the tectono- sedimentary evolution of the area.@en

Natural fracture network characteristics can be establishes from high-resolution outcrop images acquired from drone and photogrammetry. Such images might also be good analogues of subsurface naturally fractured reservoirs and can be used to make predictions of the fracture geometry and efficiency at depth. However, even when supplementing fractured reservoir models with outcrop data, gaps will remain in the model and fracture network extrapolation methods are required. In this paper we used fracture networks interpreted from two outcrops from the Apodi area, Brazil, to present a revised and innovative method of fracture network geometry prediction using the multiple-point statistics (MPS) method.

The MPS method presented in this article uses a series of small synthetic training images (TIs) representing the geological variability of fracture parameters observed locally in the field. The TIs contain the statistical characteristics of the network (i.e. orientation, spacing, length/height and topology) and allow for the representation of a complex arrangement of fracture networks. These images are flexible, as they can be simply sketched by the user.

We proposed to simultaneously use a set of training images in specific elementary zones of the Apodi outcrops in order to best replicate the non-stationarity of the reference network. A sensitivity analysis was conducted to emphasise the influence of the conditioning data, the simulation parameters and the training images used. Fracture density computations were performed on selected realisations and compared to the reference outcrop fracture interpretation to qualitatively evaluate the accuracy of our simulations. The method proposed here is adaptable in terms of training images and probability maps to ensure that the geological complexity in the simulation process is accounted for. It can be used on any type of rock containing natural fractures in any kind of tectonic context. This workflow can also be applied to the subsurface to predict the fracture arrangement and fluid flow efficiency in water, geothermal or hydrocarbon fractured reservoirs.@en

Improving the understanding of fluid flow through fracture networks is crucial to the optimum recovery of hydrocarbons in naturally fractured reservoirs. In explicit dual continuum representations of matrix and fractures, it is not just the intensity of fracturing and the topological relationships in the network but also connectivity of hydraulically open fractures that determines effective permeability of the system. Fractured folds often form prolific reservoirs owing to the structural closure they afford and the additional porosity and permeability due to the fold related fracturing. The fracture patterns are of specific interest owing to the complex geometries associated with folding. In this work we utilize a combined outcrop based and numerical approach to characterize fracture patterns, fracture apertures and fluid flow sensitivities using a folded ‘box-type’ anticlinal structure example from the Pag Island, Croatia. The Pag Island is part of the main Adriatic-Dinaridic Carbonate Platform in the External Dinarides region that persisted from the Triassic to the Eocene with Paleocene-Miocene Dinaridic deformation phases. The current day geology consists of up to 1 km thick Cenomanian - Senonian shallow water rudists bearing carbonates and about 650m thick Eocene-Oligocene Nummulitic carbonate successions. We present a 3D structural model of the Pag Island with a Discrete Fracture Network (DFN) digitized representation built from drone photogrammetry. The multiscale fracture patterns in this multilayer folded reservoir analog are classified on the basis of folding stages (pre-, syn-, post folding). FEM geomechanical modeling is used to quantify stress-sensitive heterogeneous fracture apertures with the Barton-Bandis empirical model. Permeability sensitivities of the fracture network are tested using coupled single phase fluid flow and poroelasticity simulations. The results show that hydraulic apertures are extremely sensitive to fracture orientation with respect to the shortening direction and reservoir pressure transients. Our novel approach for coupled flow & geomechanics simulations yields effective permeability tensors that are functions of both matrix and fracture conductivities and also fracture aperture variations in time. We test dynamic closure & dilation of fractures in depletion and injection scenarios and our results stress the importance of dynamic fracture apertures in structurally complex fractured reservoirs.@en

Fractures are a primary factor controlling the fluid storage and transport properties of hydrocarbon reservoirs. The quantitative characterization of fractures in outcrop analogues allows a better understanding of natural fracture systems, to extrapolate predictive laws useful for integrating the limited data available for buried reservoirs. Here we present the methodological workflow we are applying for a multiscale characterization of fracturing in a folded Cretaceous carbonate platform in the Island of Pag, in the External Dinarides of Croatia, along with our preliminary results.@en