Naturally Fractured Reservoirs Research Articles

Applying orthogonal collocation for rapid and reliable solutions of transient flow in naturally fractured reservoirs

Naturally fractured reservoirs (NFR) contain a significant portion of the worldwide oil and gas reserves. Pressure transient analysis is the most well-established methodology for characterizing these heterogeneous reservoirs based upon well-test data. Pressure transient responses (PTR) of oil and gas reservoirs to various production/injection scenarios is widely used for forecasting and optimizing their production performance and ultimate resource recoveries.In this study, orthogonal collocation (OC) which is a straightforward and very efficient approximate approach for solving differential equations is employed as a novel approach to simulate the PTR of NFRs. The governing equations describe fluid flow in NFR for pseudo-steady state conditions. Constant production rate from a wellbore and circular no-flow are employed as an inner and outer boundary conditions, respectively.The results of OC are verified with exact analytical solutions using the Laplace transform. Thereafter, the effects of three parameters (storativity ratio, interporosity flow coefficient, and radial distance of the outer boundary from the wellbore) are studied using pressure-derivative plots. Employing the superposition theorem, the pressure response of NFR to the multi-rate production from the wellbore is calculated. The results indicate that this approximate approach can predict the pressure transient response of NFRs with an acceptable accuracy, i.e., absolute average relative deviation (AARD) of 0.16%. The equations can be adapted to deal with other flow conditions, boundary conditions and fracture stimulated reservoirs. The proposed method provides a straightforward, faster and more accurate solution in comparison with other methods commonly used. As the OC method is simpler to execute than analytical solutions (e.g. Laplace Transform), it is easier to modify and expand for addressing more complex reservoir scenarios. Likewise, the numerical methods (e.g. finite difference and finite elements) commonly applied to model fractured reservoirs involve significantly more time-consuming calculations, making them more cumbersome to use in reservoir simulations than the proposed orthogonal collocation method.

Ensemble clustering for efficient robust optimization of naturally fractured reservoirs

In the development of naturally fractured reservoirs (NFRs), the existence of natural fractures induces severe fingering and breakthrough. To manage the flooding process and improve the ultimate recovery, we propose a numerical workflow to generate optimal production schedules for smart wells, in which the inflow control valve (ICV) settings can be controlled individually. To properly consider the uncertainty introduced by randomly distributed natural fractures, the robust optimization would require a large ensemble size and it would be computationally demanding. In this work, a hierarchical clustering method is proposed to select representative models for the robust optimization in order to avoid redundant simulation runs and improve the efficiency of the robust optimization. By reducing the full ensemble of models into a small subset ensemble, the efficiency of the robust optimization algorithm is significantly improved. The robust optimization is performed using the StoSAG scheme to find the optimal well controls that maximize the net-present-value (NPV) of the NFR’s development. Due to the discrete property of a natural fracture field, traditional feature extraction methods such as model-parameter-based clustering may not be directly applicable. Therefore, two different kinds of clustering-based optimization methods, a state-based (e.g., s w profiles) clustering and a response-based (e.g., production rates) clustering, are proposed and compared. The computational results show that the robust clustering optimization could increase the computational efficiency significantly without sacrificing much expected NPV of the robust optimization. Moreover, the performance of different clustering algorithms varies widely in correspondence to different selections of clustering features. By properly extracting model features, the clustered subset could adequately represent the uncertainty of the full ensemble.

Thermally-induced wettability alteration from hot-water imbibition in naturally fractured reservoirs—Part 1: Numerical model development & 1D models

The alteration of wettability can be a key mechanism for additional oil production from hydrocarbon reservoirs worldwide. This paper models thermally-induced wettability alteration from hot-water imbibition in naturally fractured reservoirs (NFRs). Hot-water (or steam) enhanced oil recovery (EOR) in fractured reservoirs can lead to increased oil recovery by enhancing water imbibition into matrix blocks, rendering the formation more water-wet. This will increase recovery as a result of decreased oil-water interfacial tension and reduced residual oil saturation.Modeling and evaluating production mechanisms in such a process in NFRs requires an understanding of multiphase flow parameters. In this work, numerical simulation codes with finite-difference formulations were developed to couple fluid flow and heat transfer for 1D and 2D flow geometries in spontaneous imbibition. This paper examines the effect of elevated temperature on wettability by considering various initial and boundary conditions. This approach results in more accurate simulation results as the relative permeability and capillary pressure curves are updated at each time step and for each grid (or each rock-type).The results from this study confirmed: a) the rate of recovery in co-current is generally higher than that in counter-current imbibition in a hot-water imbibition process, b) changing the wetting state in matrix from intermediate- or oil-wet to more water-wet proved to increase the ultimate recovery by reducing the residual oil saturation, c) updating the kr and Pc curves vs. temperature in simulating a hot-water injection process in NFRs can be more accurate than the commercial simulators where the relative permeability and capillary pressure curves are updated based on solely their end-points.

Production forecasting and uncertainty quantification for naturally fractured reservoirs using a new data-space inversion procedure

A new method for production forecasting and uncertainty quantification, applicable for realistic naturally fractured reservoirs (NFRs) represented as general discrete-fracture-matrix (DFM) models, is developed and applied. The forecasting procedure extends a recently developed data-space inversion (DSI) technique that generates production predictions using only prior-model simulation results and observed data. The method does not provide posterior (history-matched) geological models. Rather, the DSI method treats production data as random variables. The prior distribution is estimated from the flow simulations performed on prior geological models, and the posterior data-variable distribution is sampled using a data-space randomized maximum likelihood method. The DSI treatment requires the parameterization of data variables to render them approximately multivariate Gaussian. The complex production data considered here (resulting from frequent well shut-ins) is treated using a new reparameterization that involves principal component analysis combined with histogram transformation. The DSI method is first applied for two-dimensional DFM systems involving multiple fracture scenarios. In this case, comparison with a rejection sampling procedure is possible, and we show that the DSI results for P10, P50, and P90 statistics are consistent with rejection sampling results. The DSI method is then applied to a realistic NFR that has undergone 15 years of primary production and is under consideration for waterflooding. To construct the DSI representation, around 400 prior DFM models, which correspond to different geologic concepts and properties, are simulated. Two different reference ‘true’ models, along with different data-assimilation durations, are considered to evaluate the performance of the DSI procedure. In all cases, the DSI predictions are shown to be consistent with the forecasts from the ‘true’ model and to provide reasonable quantification of forecast uncertainty.

Modified shape factor incorporating gravity effects for scaling countercurrent imbibition

Imbibition is the main oil (or gas) production mechanism in water invaded naturally fractured reservoirs (NFRs). Scaling laboratory imbibition results is important in studying imbibition in actual case of NFRs. Different scaling equations have been presented in the literature for countercurrent imbibition. Important parameters such as gravity effects are required to be considered in the scaling process. Gravity effects are important in field scale where Bond Number, the ratio of gravity to capillary forces, is large enough to influence the fluid exchange between matrix and fracture system. In this study by a theoretical approach, a modified shape factor accounting for the gravity effects is presented by extension of the well-known Kazemi-Gilman-Elsharkawy (KGE) shape factor and can be used in existing countercurrent imbibitions scaling equations. To validate the presented shape factor in scaling countercurrent imbibition results, the fine grid numerical simulation technique has been used to produce a wide range of experiments. Results show that the new shape factor works well when gravity effects are considerable in comparison to capillary forces.

Geometric nature of hydraulic fracture propagation in naturally-fractured reservoirs

The geometry of hydraulic fracture propagation in the absence and presence of natural fractures in reservoirs was studied. The results revealed a marked influence of natural fractures on the symmetry of fracture propagation observed for rock free of natural fractures. Natural fracture properties such as stiffness and approaching angle, and the distance from wellbore to the natural fracture were found to influence the hydraulic fracture geometry. Furthermore, the location of the wellbore with respect to the natural fractures in a reservoir having a system of natural fractures displayed a significant influence on the resulting geometry of hydraulic fracture propagation.

An exploration of pressure dynamics using differential equations defined on a fractal geometry

Pressure tests have been used to understand the behavior of naturally fractured reservoirs (NFRs) by establishing parameters such as permeability, connectivity of fractures, system compressibility, fracture network parameters, and others associated with the physical properties of the reservoir. The complex fracture network of a NFR produces anomalous fluid flow, which is shown by the pressure behavior at the well. A plausible model to explain this behavior is to assume that it arises from a fractal fracture system. However, to estimate the parameters that define this fractal fracture system, fluid flow models based on the modification of Darcy’s law are used. On the other hand, in this work, a fractal structure with known fractal dimension: Sierpinski gasket (SG) is proposed. The objective of this work is to solve numerically the diffusion equation on SG, and establish a comparison with flow models used in the oil industry to investigate the fractality assumption. This study is focused on the qualitative behavior of the solution of the diffusion equation defined on a SG supported by the Kigami’s theory of differential equations on fractals.

Numerical simulation of water flooding in natural fractured reservoirs based on control volume finite element method

A numerical method is employed to investigate the fluid flowing dynamics in fractured reservoirs in this paper. Owing to the multi-scales and strong heterogeneity, description of fracture network systems plays a significant role for a successful fractured reservoir simulation model. Comparing to previous works, this paper proposes a combination of dual continuum and discrete fracture network (DFN) model, which is used to simulate the flow in reservoirs with multi-scale fractures and proved feasible. In the first part of the paper, implicit flow equations of oil and water phase in fractured reservoirs are established to consider the nonlinearity properties. And then the control volume finite element method based on the unstructured grid system and N-R iteration are used to obtain the numerical solution. Moreover, the accuracy of this simulator is proved to be reasonable by field data; Sensitivity analysis shows that the existences of complex multi-scale fracture networks have great impacts on water flooding. Compared with the homogeneous reservoir, natural fracture (micro and large scale) networks can change the direction and velocity of the waterfront, which finally leads to the more serious water breakthrough, higher water cut and less recovery. The research and the numerical results obtained in this paper can provide theoretical guidance for efficient and scale development of natural fractured reservoirs.

Fault reactivation and reservoir modification during hydraulic stimulation of naturally-fractured reservoirs

Hydraulically-stimulated fractures often intersect natural fractures contain within resource-bearing reservoirs. Understanding the nature of hydraulic fracture propagation, their interaction with pre-existing natural fractures and the post-interaction modifications of the reservoir is the key to design a successful reservoir stimulation. This study uses Universal Distinct Element Code (UDEC) to investigate the reactivation mechanism of natural fractures and its subsequent effects on the properties of the reservoir under reservoir conditions.Results of the simulation revealed that when a hydraulically-stimulated fracture meets a natural fracture it either crosses the natural fracture (crossing) or arrests at the intersection without opening the natural fracture (arrest) or opens the natural fracture and diverts the fluid flow (opening), subjected to the prevailing reservoir conditions. Thus, unless the interaction results in crossing, natural fractures can reactivate. Increase of approaching angle or stress anisotropy or the friction angle of the natural fracture was observed to increase the possibility of crossing. Study on the post-interaction changes of the reactivated natural fracture showed that increasing approaching angle and stress anisotropy increase the maximum shear displacement but decrease the maximum normal displacement (i.e. aperture) of the natural fracture. This behaviour was attributed to the differences of the deformation patterns of the rock blocks surrounding the intersection at different approaching angles and stress anisotropies. Friction angle of the natural fracture showed only a minor influence on its shear and normal displacement after reactivation.

Optimisation of decision making under uncertainty throughout field lifetime: A fractured reservoir example

Assessing the change in uncertainty in reservoir production forecasts over field lifetime is rarely undertaken because of the complexity of joining together the individual workflows. This becomes particularly important in complex fields such as naturally fractured reservoirs. The impact of this problem has been identified in previous and many solutions have been proposed but never implemented on complex reservoir problems due to the computational cost of quantifying uncertainty and optimising the reservoir development, specifically knowing how many and what kind of simulations to run.This paper demonstrates a workflow that propagates uncertainty throughout field lifetime, and into the decision making process by a combination of a metric-based approach, multi-objective optimisation and Bayesian estimation of uncertainty. The workflow propagates uncertainty estimates from appraisal into initial development optimisation, then updates uncertainty through history matching and finally propagates it into late-life optimisation. The combination of techniques applied, namely the metric approach and multi-objective optimisation, help evaluate development options under uncertainty. This was achieved with a significantly reduced number of flow simulations, such that the combined workflow is computationally feasible to run for a real-field problem.This workflow is applied to two synthetic naturally fractured reservoir (NFR) case studies in appraisal, field development, history matching and mid-life EOR stages. The first is a simple sector model, while the second is a more complex full field example based on a real life analogue. This study infers geological uncertainty from an ensemble of models that are based on the carbonate Brazilian outcrop which are propagated through the field lifetime, before and after the start of production, with the inclusion of production data significantly collapsing the spread of P10-P90 in reservoir forecasts. The workflow links uncertainty estimation with the appropriate optimisation at appraisal, development and reservoir management stages to maximise oil recovery under uncertainty.

Permeability upscaling in fractured reservoirs using different optimized mother wavelets at each level

We use a multi-resolution analysis based on a wavelet transform to upscale a 3D fractured reservoir. This paper describes a 3D, single-phase, and black-oil geological model (GM) that is used to simulate naturally-fractured reservoirs. The absolute permeability and porosity of GM is upscaled by all the possible combinations of Haar, Bior1.3, and Db4 wavelets in three levels of coarsening. The applied upscaling method creates a non-uniform computational grid, which preserves its resolved structure in the near-well zones as well as in the high-permeability sectors but the data are scaled up in the other regions. To demonstrate the accuracy and efficiency of the method, the values for the oil production rate, mean reservoir pressure, water cut, and total amount of water production are studied, and their mean error is estimated for the upscaled models. Finally, the optimized model is selected based on the computation time and accuracy value.

A new production predicting model of fractured horizontal wells in dual-porosity gas reservoirs on non-Darcy flow conditions

Dual-porosity is a common method to model natural fractured reservoirs or complex fracture network after volume hydraulic fracturing. To analyze the productivity of fractured horizontal gas wells, a new volumetric source model with high velocity non-Darcy flow in hydraulic fractures is developed. The basic volumetric source function is solved by utilizing orthogonal transformation in real space, which solves the problem that the non-linear equation (indicating non-Darcy effect) cannot adopt Laplace transformation. The volumetric source model is verified by the tri-linear flow model and a field example. Results shows increasing width of hydraulic fractures and enlarging size of proppant have significant effect on weaken non-Darcy flow. The volumetric source model is a fast and accurate method to predict the productivity. In addition, this model can provide a more reasonable method to optimize hydraulic fracturing considering non-Darcy flow effect.

Experimental and simulation study of gas diffusion effect during gas injection into naturally fractured reservoirs

Naturally Fractured Reservoirs (NFRs) contain a large portion of oil reserves. Most of NFRs are subjected to secondary and tertiary recovery schemes due to their low primary recovery. Gas injection into NFRs has received much attention in recent years. The main mechanisms contributing to oil recovery during gas injection into NFRs are viscous flow, gravity drainage and diffusion. The viscous flow rarely happens in NFRs due to low pressure drop and early breakthrough of injected gas in high conductive fractures. Gravity drainage is also important in fractured reservoirs with tall matrix blocks where gravity force overcomes capillary force. Diffusion is another recovery mechanism that is found to have a significant role in recovery of oil from NFRs. This has been affirmed by numerous experimental and simulation investigations in the literature. However, sole effect of this mechanism is not well recognized especially in NFRs with very low matrix permeability.In the current work, we have experimentally studied the effect of diffusion and viscous flow on oil recovery from NFRs with tight matrix blocks. The relative importance of each mechanism which reflects the impact of convection versus diffusion is investigated. We have also studied the sole effect of diffusion on final oil recovery using two types of gas (helium and nitrogen) with different diffusion coefficients. Results show that effect of diffusion in tight reservoirs is significant and comparable to effect of viscous flow. Numerical simulation also was conducted to verify results obtained in four experiments involving nitrogen injection. Simulation results reveal that current models for diffusion do not take into account the role of diffusion in ultimate oil recovery properly.

Optimal Design of Low-Temperature Air Injection with Propane for Efficient Recovery of Heavy Oil in Deep Naturally Fractured Reservoirs: Experimental and Numerical Approach

Low-temperature air/solvent injection (LTASI) can be a possibility if injected air/solvent into a fractured reservoir diffuses into the matrix effectively to oxidize oil in it while reducing its viscosity by temperature and solvent dissolution. However, early breakthrough of air with partial consumption of oxygen as a result of the highly conductive nature of the reservoirs is a concern. Once it is controlled by a proper injection scheme and consumption of air injected through efficient diffusion into the matrix, low-temperature air injection (LTAI) can be an alternative technique for heavy-oil recovery from deep naturally fractured reservoirs (NFRs). Limited number of studies on light oils showed that this process was highly dependent upon the oxygen diffusion coefficient and matrix permeability. In this process, oil production is governed by drainage and stripping of light oil components, which have a greater effect on recovery than the swelling of oil. In the present study, static laboratory tests were...

Fracture-matrix interactions during immiscible three-phase flow

Abstract Naturally Fractured Reservoirs (NFR) contain a significant amount of remaining petroleum reserves and are now considered for Enhanced Oil Recovery (EOR) schemes that involve three-phase flow such as water-alternating-gas (WAG) injection. Reservoir simulation of three phase flow is challenging because a proper set of flow functions, i.e. relative permeability and capillary pressure functions, that describe the underlying physics of fluid displacement is vitally important to obtain reliable production forecasts but associated with high uncertainty. For NFR, another challenge is the upscaling of recovery processes, particularly fracture-matrix transfer during three-phase flow, to the reservoir scale using dual porosity or dual permeability models. In this work we approach a solution to these challenges by analysing three-phase flow during WAG injection at various scales, starting at the pore scale and then move on to an intermediate scale which is comparable to the scale of a single reservoir simulation grid block. At this scale, we represent fractures and matrix using a fine-grid model that employs empirical and pore-network modelling derived three-phase flow functions to study the effect of capillary and gravity forces on fracture-matrix transfer. We also consider different matrix wettabilities and permeabilities, as well as matrix block size distributions. We then perform an upscaling step that is typical for field-scale recovery simulations and use the dual porosity model to represent fracture-matrix transfer processes that were observed at the grid-block scale. This enables us to analyse and improve the accuracy of dual porosity models for three-phase displacement processes inherent to WAG in NFR. We find that different three-phase saturation profiles develop inside matrix blocks, which are strongly dependent on wettability of the matrix. These profiles have a profound impact on recovery during WAG injection. The classical dual porosity model fails to capture these saturation profiles and hence miscalculates recovery during early WAG cycles. We present a double block dual porosity model, i.e. a simple multiple continua model, which better matches the fine grid simulation results.

Fracture properties analysis and discrete fracture network modelling of faulted tight limestones, Murge Plateau, Italy

The modelling of natural fracture in reservoirs requires, as input data, the results of previous detailed and accurate analysis of the 3D fracture network. These data could be derived from well logs and production tests (which however limit our understanding of the fracture geometry, intensity and distribution) and outcrop analogues. Data obtained applying scanline and scanarea methodologies on rocks exposed at the surface, in fact, allow the construction of more representative numerical models of natural fractured reservoirs. This paper focuses on with the (DFN) modelling of natural fractures associated to strike-slip faults crosscutting tight carbonates, which are exposed along vertical walls and pavements of an inactive quarry of the Murge area, southern Italy. The studied outcrops expose the inner structure of two conjugate fault zones striking WNW-ESE and NNW-SSE, respectively. DFN models were built according to the spatial and dimensional properties computed for the natural fracture network. The results of these models show that the overall fault permeability is 3-to-4 orders of magnitude higher than the host rock permeability. The fault damage zones form the main fluid conduits, with the highest permeability values computed for fault-parallel fluid flow. Such a pronounced permeability anisotropy obtained for the fault damage zone is mainly related to the fracture dimension, both lengths and heights, and their aperture values.

A comparative study of non-Darcy flows in naturally fractured gas reservoirs

Numerical reservoir simulation is applied to obtain forecasts for flow in hydrocarbon reservoirs under different production strategies. Considering heterogeneities, which may occur in different length scales, there is significant interest in fractures. In naturally fractured reservoirs (NFRs), for example, differences in permeability and porosity values are due to geological factors. In this work, a numerical reservoir simulator was built for the purpose of studying gas flow in NFRs. The physical–mathematical modeling considers single-phase and isothermal three-dimensional flow. Non-Darcy effects are incorporated using Forchheimer’s equation and the Barree and Conway’s model for considering the inertial effects. The nonlinear partial differential equations are discretized by means of the finite-difference method along with a time-implicit approach. The numerical code also allows grid refinement to represent fractures and providing a better capture of physical phenomena close to fractures and wellbores. A preconditioned approximate factorization technique was chosen for the numerical solution due its ability to solve matrix equations for problems where heterogeneity is an important feature. Different production scenarios were studied for hydrocarbons recovery. It was possible to conclude that spatial distribution and wide variation of heterogeneity values have direct influence in the pressure and velocity fields in porous media, and also impact on the wellbore pressure profile. When non-Darcy flow occurs in naturally fractured reservoirs there is a counterbalance between fracture effects, which reduce wellbore pressure drop, and the inertial effects, that increase wellbore pressure drop. Therefore, an accurate modeling of these interactions is fundamental to forecast reservoir performance.

Analysis of pressure falloff tests of non-Newtonian power-law fluids in naturally-fractured bounded reservoirs

Abstract Application of non-Newtonian Power-law fluids (e.g. polymeric solutions) for production enhancement in petroleum reservoirs has increased over the last three decades. These fluids are often injected as viscous solutions to improve mobility ratio and enhance oil recovery during chemical flooding. As part of the flooding operation, surfactant (or micellar) solutions are first injected at the leading edge of the flood to reduce interfacial tension between water and oil. Subsequently, a slug of polymer solution is injected ahead of normal water to increase viscosity of the water, improve volumetric sweep efficiency and accelerate oil production. Analysis of pressure tests conducted pre and post injection, to evaluate mobility of these fluids, is more demanding than conventional techniques, which were developed strictly for Newtonian fluids. In naturally-fractured reservoirs, flow of non-Newtonian fluids is more complex due to fracture-matrix interaction which is usually resonated in the pressure footprints. Some models have been developed to aid interpretation of pressure tests, but boundary effects on down-hole measurements due to structural discontinuity and presence of an active aquifer, have not been thoroughly investigated. This article presents an analytic technique for interpreting pressure falloff tests of non-Newtonian Power-law fluids in wells that are located near boundaries in dual-porosity reservoirs. First, dimensionless pressure solutions are obtained and Stehfest inversion algorithm is used to develop new type curves. Subsequently, long-time analytic solutions are presented and interpretation procedure is proposed using direct synthesis. Two examples, including real field data from a heavy oil reservoir in Colombian eastern plains basin, are used to validate and demonstrate application of this technique. Results agree with conventional type-curve matching procedure. The approach proposed in this study avoids the use of type curves, which is prone to human errors. It provides a better alternative for direct estimation of formation and flow properties from falloff data.

Fractured-Reservoir Modeling and Interpretation

SummaryFractures are common features of many well-known reservoirs. Naturally fractured reservoirs (NFRs) consist of fractures in igneous, metamorphic, and sedimentary rocks (matrix). Faults in many naturally fractured carbonate reservoirs often have high-permeability zones and are connected to numerous fractures with varying conductivities. In many NFRs, faults and fractures frequently have discrete distributions rather than connected-fracture networks. Because faulting often creates fractures, faults and fractures should be modeled together. Accurately modeling NFR pressure-transient behavior is important in hydrogeology, the earth sciences, and petroleum engineering, including groundwater contamination to shale gas and oil reservoirs. For more than 50 years, conventional dual-porosity-type models, which do not include any fractures, have been used for modeling fluid flow in NFRs and aquifers. They have been continuously modified to add unphysical matrix-block properties such as matrix skin factor.In general, fractured reservoirs are heterogeneous at different length scales. It is clear that even with millions of gridblocks, numerical models may not be capable of accurately simulating the pressure-transient behavior of continuously and discretely NFRs containing variable-conductivity fractures. The conventional dual-porosity-type models are obviously an oversimplification; their serious limitations for interpreting well-test data from NFRs are discussed in detail. These models do not include wellbore-intersecting fractures, even though they dominate the pressure behavior of NFRs for a considerable length of testing time. Fracture conductivities of unity to infinity dominate transient behavior of both continuously and discretely fractured reservoirs, but again, dual-porosity models do not contain any fractures. Our fractured-reservoir model is capable of treating thousands of fractures that are periodically or arbitrarily distributed with finite- and/or infinite conductivities, different lengths, densities, and orientations.Appropriate inner-boundary conditions are used to account for wellbore-intersecting fractures and direct wellbore contributions to production. Wellbore-storage and skin effects in bounded and unbounded systems are included in the model. Three types of damaged-skin factors that may exist in wellbore-intersecting fracture(s) are specified. With this highly accurate model, the pressure-transient behavior of conventional dual-porosity-type models are investigated, and their limitations and range of applicability are identified. The behavior of the triple-porosity models is also investigated. It is very unlikely that triple-porosity behavior is caused by the local variability of matrix properties at the microscopic level. Rather, it is caused by the spatial variability of conductivity, length, density, and orientation of the fracture distributions. Finally, we have presented an interpretation of a field-buildup-test example from an NFR by use of both conventional dual-porosity models and our fractured-reservoir model.A substantial part of this paper is a review and discussion of the earlier work on NFRs, including the authors’ work.

Background fractures in carbonates: inference on control of sedimentary facies, diagenesis and petrophysics on rock mechanical behavior. Example of the Murge Plateau (southern Italy)

Characterizing fracture networks in Naturally Fractured Reservoirs (NFR) is a major challenge for hydrocarbon exploration and production. The fracture organization is: i) a key parameter for fluid flow understanding in carbonates (in a general sense) and ii) the key parameter in tight, non-porous carbonates. However, at present-day, the fracture parameters from subsurface data are not sufficient to define the 3D distribution of a fracture network. Moreover, in carbonate reservoirs, fracture occurrence strongly depends on the mechanical properties of the host rock such that characterizing fractures is only possible through the close study of the host rock heterogeneities. Studying fractures in outcrop analogues allows accessing to 3D fracture patterns, determining the host rock mechanical properties and their impact on fracture distribution. In this paper, we trace the conditions for the fracturing process through the geodynamic history of the reservoir. We aim at determining the sedimentary and diagenetic controls on fracture patterns and the genetic correlation with tectonic and burial history.To this purpose, we have targeted two formations made of platform carbonates from the Murge Plateau. We analyzed the fracture patterns and sedimentary facies as well as the tectonic, diagenetic and burial history for each studied site. Fracture patterns are characterized from geometrical, kinematic and diagenetic criteria based on field and laboratory measurements. Fracture sequences are defined based on cross-cutting and abutting relationships and compared with geodynamic history.Fractures are bed-perpendicular joints and veins, and numerous bed-parallel stylolites. We observe a stage of fracturing synchronous with shallow burial and prior to major tectonic events. Carbonates have undergone early diagenesis during fast and shallow burial, conferring early brittle behavior. Fracture development, mechanical and petrophysical properties are acquired during early burial.