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Geological and geophysical data from exploration hydrocarbon industry are valuable for reservoir characterisation. In case of abandoned hydrocarbon fields, these data are often made public but limited to vintage data due to confidential policies of oil companies. In Italy, the Adriatic Sea represents a successful hydrocarbon exploration province where a significant amount of geological and geophysical legacy data is public available.Based on collection and processing of these data, mostly acquired during the second half of the XX Century, this work proposes a methodology aimed at 3D modelling and characterisation of the siliciclastic and carbonate reservoir rocks. Modelling of the petrophysical properties was carried out using different approaches, according to the lithology of reservoir. The results show how the adopted workflow allows the understanding of the relationship among stratigraphic, structural and petrophysical properties.

In carbonates rocks, the textural properties of the pore network (e.g., pores size distribution, pores shape, pores connectivity and tortuosity), and therefore the porosity and permeability, are highly variable due to primary depositional conditions, diagenesis processes and deformation. For this reason, the quantitative characterisation of carbonate reservoirs, in terms of porosity and permeability, is challenging. This study presents a methodology for investigating the pore network in carbonate rocks using high-resolution synchrotron X-ray computed microtomography (SR micro-CT). This could be combined with computational fluid dynamics (CFD) simulations for obtaining information about fluid transport and calculated the permeability of the samples. Using key samples from rocks corresponding to porous and tight carbonates exposed in south and central Italy, the methodology has been applied to three different study cases: rapid characterisation of porous carbonate reservoirs (Abruzzo, central Italy), quantitative analysis of deformed porous carbonates (Sicily, south Italy), and pore-scale assessment of fractures hosted in tight carbonates (Murge, south Italy). Some samples may contain deformation structures (i.e. deformation bands, fractures) or may be altered by diagenesis (e.g., cementation, dissolution). The pore space can be filled by a single fluid phase (i.e. air) or multiple (i.e. bitumen and trapped gas). The selected rock samples were scanned by means of phase-contrast synchrotron SR micro-CT at the SYRMEP beamline of the Elettra synchrotron in Trieste (Italy). The tomographic images were acquired using a multi-resolution approach with a pixel size variable in the range of 1.0–2.4 μm depending on the grain size distribution of the rock sample. After reconstruction, images were filtered and segmented for characterising the pore phase. The resulting images were used for both performing a quantitative pore network analysis of the studied rock samples and CFD experiments (multiple relaxation times lattice-Boltzmann method, MRT-LBM) using the open source software PALABOS.

This study consists of a three-dimensional (3D) assessment of the pore network properties (i.e., porosity, pore connectivity, specific surface area) in deformed carbonate grainstones cropping out in Sicily and Abruzzo regions (Italy). Previous studies, including microphotography, mercury injection analysis, and in-situ air permeameter measurements, have reported permeability differences (in the range of two-to-three orders of magnitude) between the carbonate grainstones exposed in Sicily and Abruzzo, that cannot be explained by only considering the differences of porosity. In this study, the pore network properties of suitable rock samples were studied by quantitative analysis of X-ray micro-CT images using both synchrotron and microfocus sources. On the basis of the results, inferences about the control of pore network properties on permeability were made for both host rock and deformation bands. In the host rocks, high values of connectivity seem to be associated with high values of permeability, whereas higher values of the specific surface area seem to correspond to lower permeability. Within the deformation bands (DBs), both porosity and pore connectivity are reduced except for local solution-enlarged stylolites and fractures (slip surfaces) preferentially connected parallel to the DB.

The characterization and modeling of fractures in karsted carbonate reservoirs are challenging due to the mechanical interactions between fractures and irregular karst elements. This study proposes an integrated approach for characterizing and modeling large-scale fractures within deeply buried fractured karst carbonates of the Yingshan Formation (Ordovician in age) located at the Tahe oilfield, Tarim Basin (western China). This investigation implements a promising workflow to stochastically model the fracture sets interpreted from borehole image logs and compute both fracture porosity and permeability tensor in karsted carbonates. For this case study, we have constructed a Discrete Fracture Network (DFN) by combining two structural seismic attributes (i.e. local structural dip and ant-tracking). We have also applied the automatic fault extraction (AFE) algorithm. The results indicate that this method detects a greater number of discontinuities associated with fractures compared to the conventional methods employed in this kind of reservoir (e.g. seismic coherence and curvature). The fracture set with higher values of fracture porosity and permeability coincided with the orientation of maximum horizontal stress, WSW-ENE. In the model, the highest values of fracture intensity correspond to the most productive oil wells. Finally, this study highlights the importance of fracture modeling for evaluating the distribution of the most favorable production areas, so-called sweet-spots, in karsted carbonates reservoirs.

Fracture networks in porous carbonates can control, assist, or even contribute negatively to reservoir quality. In scenarios where fractures and matrix pore systems are of similar importance, a dual-porosity/permeability (DP/P) modeling approach is necessary or at least recommendable for the reservoir characterization. These workflows are well established at the reservoir scale, however at the microscale, the interaction between fractures and porous matrix needs to be further investigated. The aim of this work is to assess the contribution of meter-scale fractures (macrofractures) to the porosity and permeability in a porous carbonate reservoir analogue at the microscale. To reach this objective, we created DP/P models at the microscale through the integration of two different methods of 3D imaging such as, high-resolution synchrotron X-ray microtomography (SR micro-CT) and Structure from Motion (SfM) photogrammetry. Quantitative analyses of pristine rock and DP/P models were performed to evaluate the contribution of macrofracture segments to the porosity and connectivity of the pore network. These results were integrated with single-phase flow simulations for calculating permeability values. Different scenarios were modeled in order to systematically evaluate the control exerted by fracture roughness parameters (i.e., asperity height distribution and fractal dimension) on porosity and permeability in various lithofacies. The key analyzed samples come from the Roman Valley quarry located at the Majella Mountain (central Italy), which has been widely investigated due to the presence of consistent bitumen impregnations distributed in pervious medium-to-coarse grainstones and along two main fault zones. The results of this study demonstrate the utility of obtaining DP/P microscale models as complementary approach to explain the hydrocarbon distribution in fractured multi-facies porous carbonates. We document the potential of macrofracture segments to provide neo-connected porosity by linking up adjacent isolated or partially isolated matrix pore networks in impervious carbonate rocks. In pervious carbonate lithofacies, fault-related macrofractures can enhance permeability and contribute to bitumen migration and distribution, whereas the increment of storage capacity is limited since these rocks are already fully connected. In the case of impervious carbonate lithofacies, results indicate that the actual contribution of neo-connected pores to fluid transport is limited, which agrees with outcrop observations.

This work assesses the impact of the stratigraphic and structural heterogeneities on the fluid distribution and migration within a deformed carbonate reservoir analogue. The study was carried out in the abandoned Roman Valley quarry (Majella Mountain, central Italy), well-known for its historical bitumen extraction. The studied rocks consist of ramp carbonates of the lower member of the Bolognano Formation (Oligocene-Miocene in age) mainly composed of grainstones, and secondary packstones and wackestones. In the quarry, the exposed rocks are crosscut by two high-angle oblique-slip faults striking WNW-ESE with up to 40 m of throw. With the aim of deciphering the contribution of both matrix and fracture pore space on the fluid storage and migration, both laboratory measurements and field-based Discrete Fracture Network (DFN) models (cubes with 4-m per side) have been carried out. The obtained dual-porosity/permeability model, which includes the lithological and the structural heterogeneities observed at the location, was used to run flow simulations under different scenarios of well locations. The fluid distribution in the matrix, resulting from these flow simulations, is consistent with field observations where bitumen localizes within the most permeable lithofacies (grainstones). In the fault zones, the fracture network causes an important fluid flow anisotropy, enhancing the flow in a direction subparallel to the faults. The flow orthogonal to the fault zones is controlled by type and lateral continuity of fault rocks, where fault breccias represent conduits and cataclasites localized barriers.

This work focuses on the spacing and height distributions of bed-perpendicular fracture sets present within a carbonate multilayer, and on their effect on the volumetric (P32 and fracture porosity) and hydraulic (correspondent permeability) properties of the rock mass computed after DFN modelling. Results of integrated field and laboratory analyses are consistent with an uneven spacing distribution of Strata-Bound (SB) fractures. The oldest SB fractures formed within individual limestone beds bounded by bed interfaces, which likely acted as mechanical interfaces. Differently, the youngest SB fractures formed within smaller rock volumes bounded by the pre-existing fractures. Non Strata-Bound (NSB) fractures consist on sheared bed-perpendicular fractures, originally compartmentalized within individual beds, which now form incipient strike-slip faults. DFN modelling of representative rock volumes show that both volumetric and hydraulic properties are strongly affected by the two main sets of NSB fractures, which form a conjugate system of faults producing the principal structural anisotropy in the fractured carbonate multi-layer.

The work tackles the control exerted by a sub-seismic fracture network on both secondary porosity and correspondent permeability of outcropping tight carbonates. Taking advantage of excellent 3D exposures, located in the Murge Plateau of southern Italy, the fracture network is investigated at different scales of observation. The rock multi-layer is made up of 10's of cm-thick, sub-horizontal, laterally continuous limestone beds crosscut by stratabound fractures, non-stratabound fractures, and small faults named as persistent fracture zones with low amounts of offset. Stratabound fractures consist of bed-perpendicular joints and sheared joints, non-stratabound fractures of incipient, cm-offset, sub-vertical faults, whereas the 10's of cm-offset persistent fracture zones are made up of 10's of m-high, m-thick fractured damage zones. The aforementioned structural elements localize within discrete carbonate units bounded by primary features such as bed surfaces, prominent surfaces and sedimentary breccia horizons. Such interfaces therefore affected the fracture stratigraphy of the limestone rock, and thus impact the fluid flow properties of the carbonate multilayer by compartmentalizing deformation. In the field, the fracture network is investigated by means of scanline and scan area methodologies to document the orientation, intensity, height distribution, mechanical aperture and roughness of individual fractures exposed along vertical outcrops and pavements of abandoned quarries. Then, Discrete Fracture Network (DFN) models of representative geocellular volumes are built, according to the different scales of analysis, to compute both fracture porosity and correspondent permeability (K xx , K yy , K zz ). Results of such a work show that the most prominent non-stratabound fracture set forms the major control on fluid storage and migration at the scales of single beds and bed-packages. At a larger scale, we document that fluid migration mainly occurs along the persistent fracture zones, which enhance the fault-parallel flow. As a whole, the persistent fracture zones form localized fluid conduits embedded within carbonate matrices that show isotropic fluid flow properties.