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Geofluid reservoirs located in heterolithic successions (e.g., turbidites) can be affected by vertical and lateral compartmentalization due to interbedded fine-grained facies (i.e., shale, siltstones) and the presence of faults, respectively. A fault can behave as a conduit or barrier to fluid flow depending on its architecture and the individual hydraulic behavior of its components (i.e., fault core, damage zone). The fault core, normally composed by fault rock or smeared clay material, commonly acts as a flow inhibitor across the fault. Fault-related fractures (macro- and microscopic) in the damage zone generally increase the permeability parallel to the fault, except when they are cemented or filled with gouge material. Although macrofractures (which define the fracture porosity) dominate fluid flow, the matrix porosity (including microfractures) begins to have a more important role in fluid flow as the aperture of macrofractures is occluded, particularly at greater depth. This study investigates the variation in matrix permeability in fault zones hosted in heterolithic successions due to fault architecture and stratigraphy of host rock (i.e., sand-rich turbidites). Two key areas of well-exposed, faulted Miocene turbidites located in central and southern Italy were selected. For this study, six separate fault zones of varying offset were chosen. Each impacts heterolithic successions that formed under similar tectonic conditions and burial depths. Across the selected fault zones, an extensive petrophysical analysis was done in the field and laboratory, through air permeameter measurements, thin section, and synchrotron analysis in both host rock, damage zone, and fault core. Results suggest that the amount and distribution of clay layers in a heterolithic sequence affects fluid flow across the fault, regardless of fault offset.

This study outlines a probabilistic model based on artificial neural networks applied to the deeply-buried karsted carbonates of the Ordovician Yingshan Formation, which represent significant oil reservoirs in western China. The complexity of both rock type prediction and 3D facies modeling of paleokarst fillings, which are hosted within the cavities, drives the need to apply innovative techniques for identifying new oil plays. Due to the high heterogeneity of clastic fillings and patchy continuity of the karst patterns, physical evaluation of these reservoirs is extremely complex. We propose the Democratic Neural Networks Association (DNNA) as the probabilistic technique to solve these challenges. This technique simultaneously runs several artificial neural networks in parallel and combines seismic data and well logs. The resulting probable facies volume is expected to provide an appropriate distribution and delineation of clastic fillings (i.e., conglomerates, fine-grained sandstones, siltstones, mudstone, dolomite fragments, and sparry calcarenite) and unfilled or empty spaces. This calculated volume is then used as a reliable input data to condition trend analysis on a very fine geological grid, in order to model the complex patterns in question. The static model obtained shows that, the probabilistic distribution of each filling has the same orientation as karst system. Likewise, spatial dimensions similar to the proposed analogue model of these patterns (vertical and horizontal scales) are delineated. Finally, we validated prediction results by comparing them with the interpreted karst facies of a well not initially considered in the 3D model. The results indicating that the DNNA technique proves to be a useful innovative tool for generating realistic depictions of fillings deposited within deeply-buried paleokarst.

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.

The textural and geometrical properties of the pore networks (i.e., such as pore size distribution, pore shape, connectivity, and tortuosity) provides a primary control on the fluid storage and migration of geofluids within porous carbonate reservoirs. These properties are highly variable because of primary depositional conditions, diagenetic processes and deformation. This issue represents an important challenge for the characterization and exploitation plan in this type of reservoirs. In this study, the complementary properties of neutrons and X-ray experiments are carried out to better understand the effects of pore network properties on the hydraulic behavior of porous carbonates. Neutrons have unique properties and are particularly suitable for this study due to the sensitivity of neutrons to hydrogen-based fluids. The used methodology combines dynamic neutron radiography (NR), integrated X-ray and neutron tomography (XCT, NCT), and computational fluid dynamics simulations (lattice-Boltzmann method) of porous carbonate reservoir analogs from central and southern Italy. Dynamic 2D NR images provide information regarding the fluid transport and the wetting front dynamics related to the effect of heterogeneities (e.g., fractures and deformation bands) at the microscale. The combination of NCT (dry and wet samples) and XCT (dry), generates more information regarding the effective pore space contribution to fluid flow. The fluid flow simulations generate information about the connected pore network and the permeability evaluated rock sample at saturated condition.

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.

Fluid flow through a single fracture is traditionally described by the cubic law, which is derived from the Navier-Stokes equation for the flow of an incompressible fluid between two smooth-parallel plates. Thus, the permeability of a single fracture depends only on the so-called hydraulic aperture which differs from the mechanical aperture (separation between the two fracture wall surfaces). This difference is mainly related to the roughness of the fracture walls, which has been evaluated in previous works by including a friction factor in the permeability equation or directly deriving the hydraulic aperture. However, these methodologies may lack adequate precision to provide valid results. This work presents a complete protocol for fracture surface mapping, roughness evaluation, fracture modeling, fluid flow simulation, and permeability estimation of individual fracture (open or sheared joint/pressure solution seam). The methodology includes laboratory-based high-resolution structure from motion (SfM) photogrammetry of fracture surfaces, power spectral density (PSD) surface evaluation, synthetic fracture modeling, and fluid flow simulation using the Lattice-Boltzmann method. This work evaluates the respective controls on permeability exerted by the fracture displacement (perpendicular and parallel to the fracture walls), surface roughness, and surface pair mismatch. The results may contribute to defining a more accurate equation of hydraulic aperture and permeability of single fractures, which represents a pillar for the modeling and upscaling of the hydraulic properties of a geofluid reservoir.

We present the results of 3-D monitoring of strain along active faults outcropping in the central Apennines, where recent and historical strong earthquakes occurred, using TM-71 extensometers during the period 2002–2017. We discuss the fault slip development as well as kinematics particularly in the light of local recent seismicity. The recorded fault slip corresponds to the minimum and maximum principal stress with a SW-NE orientation and slightly dipping to SW. Moreover, the detected fault slip is non-linear and affected by remarkable transient periods of acceleration, which lasted up to several months. The recorded accelerations were induced by alternation of extensional, reverse and horizontal displacement due to switching extensional and compressional stress/strain state and coincide with periods of major seismic events that recently affected the central Apennines. This phenomenon is being investigated. In the case of the moderate L'Aquila 2009 and Norcia 2016 earthquakes, the recorded fault slips can be characterized as pre-seismic.

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.

In deformed porous carbonates, the architecture of the pore network may be modified by deformation or diagenetic processes altering the permeability with respect to the pristine rock. The effects of the pore texture and morphology on permeability in porous rocks have been widely investigated due to the importance during the evaluation of geofluid reservoirs. In this study, these effects are assessed by combining synchrotron X-ray computed microtomography (SR micro-CT) and computational fluid dynamics. The studied samples pertain to deformed porous carbonate grainstones highly affected by deformation bands (DBs) exposed in Northwestern Sicily and Abruzzo regions, Italy. The high-resolution SR micro-CT images of the samples, acquired at the SYRMEP beamline of the Elettra - Sincrotrone Trieste laboratory (Italy), were used for simulating a pressure-driven flow by using the lattice-Boltzmann method (LBM). For the experiments, a multiple relaxation time (MRT) model with the D3Q19 scheme was used to avoid viscosity-dependent results of permeability. The permeability was calculated using Darcy's law once steady conditions were reached. After the simulations, the pore-network properties (effective porosity, specific surface area, and geometrical tortuosity) were calculated using 3D images of the velocity fields. These images were segmented considering a velocity threshold value higher than zero. The study showed that DBs may generate significant heterogeneity and anisotropy of the permeability of the evaluated rock samples. Cataclasis and cementation process taking place within the DBs reduce the effective porosity and therefore the permeability. Contrary to this, pressure dissolution and faulting may generate connected channels which contribute to the permeability only parallel to the DB.

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.