Accounting for poro-mechanical effects in full-field reservoir simulation studies and uncertainty quantification workflows is still limited, mainly because of their high computational cost. We introduce a new approach that couples hydrodynamics and poro-mechanics with dual-porosity flow diagnostics to analyse how poro-mechanics could impact reservoir dynamics in naturally fractured reservoirs without significantly increasing computational overhead. Our new poro-mechanical informed dual-porosity flow diagnostics account for steady-state and singlephase flow conditions in the fractured medium while the fracture-matrix fluid exchange is approximated using a physics-based transfer rate constant which models two-phase flow using an analytical solution for spontaneous imbibition or gravity drainage. The deformation of the system is described by the dualporosity poro-elastic theory, which is based on mixture theory and micromechanics to compute the effective stresses and strains of the rock matrix and fractures. The solutions to the fluid flow and rock deformation equations are coupled sequentially. The governing equations for fluid flow are discretised using a finite volume method with two-point flux-approximation while the governing equations for poro-mechanics are discretised using the virtual element method. The solution of the coupled system considers stress-dependent permeabilities for fractures and matrix. Our framework is implemented in the open source MATLAB Reservoir Simulation Toolbox (MRST). We present a case study using a fractured carbonate reservoir analogue to illustrate the integration of poro-mechanics within the dual-porosity flow diagnostics framework. The extended flow diagnostics calculations enable us to quickly screen how the dynamics in fractured reservoirs (e.g. reservoir connectivity, sweep efficiency, fracture-matrix transfer rates) are affected by the complex interactions between poro-mechanics and fluid flow where changes in pore pressure and effective stress modify petrophysical properties and hence impact reservoir dynamics. Due to the steady-state nature of the calculations and the effective coupling strategy, these calculations do not incur significant computational overheads. They hence provide an efficient complement to traditional reservoir simulation and uncertainty quantification workflows as they enable us to assess a broader range of reservoir uncertainties (e.g. geological, petrophysical and hydro-mechanical uncertainties). The capability of studying a much broader range of uncertainties allows the comparison and ranking from a large ensemble of reservoir models and select individual candidates for more detailed full-physics reservoir simulation studies without compromising on assessing the range of uncertainties inherent to fractured reservoirs.

Flow modelling challenges in fractured reservoirs have led to the development of many simulation methods. It is often unclear which method should be employed. High-resolution discrete fracture and matrix (DFM) studies on small-scale representative models allow us to identify dominant physical processes influencing flow. We propose a workflow that utilizes DFM studies to characterize subsurface flow dynamics. The improved understanding facilitates the selection of an appropriate method for large-scale simulations. Validation of the workflow was performed via application on a gas reservoir represented using an embedded discrete fracture model, followed by the comparison of results obtained from hybrid and dual-porosity representations against fully explicit simulations. The comparisons ascertain that the high-resolution small-scale DFM studies lead to a more accurate upscaled model for full field simulations. Additionally, we find that hybrid implicit–explicit representations of fractures generally outperform pure continuum-based models.

Fractures can have variable effects on fluid flow in a porous rock. Moderately conductive fractures may enhance the rock's overall effective permeability, while highly conductive fractures may completely dominate fluid transport. Fluid flow modeling is important to quantify the impact of fractures on the performance of a reservoir. However, simulating fluid flow is computationally intensive due to the heterogeneities introduced by the fracture network. In this work, complex fracture patterns are simplified using hybrid implicit-explicit representations to yield a computationally tractable model. Hybrid modeling requires the selection of a partitioning size to group fractures by size. Small fractures are upscaled with the rock matrix; large fractures are explicitly represented. Our study shows that, given a naturally fractured reservoir, an upper limit exists for the partitioning size and that this threshold partitioning size can be determined without trial and error. Using artificial and realistic fracture patterns, we created hybrid models using different partitioning sizes and subjected them to pressure drawdowns. Simulated production rates were compared against reference results obtained from simulations on the original fracture patterns. Beyond a threshold partitioning size unique to each fracture pattern, hybrid model results deviate significantly from reference solutions. The threshold is identified from the relationship between upscaled permeabilities and partitioning sizes and corresponds to the point where the effective permeability of small fractures begins to increase rapidly. The permeability-size relationship is obtained using numerical flow-based upscaling. For uniformly distributed fractures with no abutment relationships, the effective medium theory is shown to generate accurate permeability-size relationships.

Hydro-mechanical coupling is imperative when the stress disturbances induced by production/injection processes affect the reservoir performance. However, the application of coupled hydro-mechanical models in actual fullfield studies is still limited, mainly because of the high computational cost. Despite the existence of simplified coupling strategies (one-way coupling and loose coupling) that reduce the computational cost, numerical simulations remain challenging because of the significant computing time required to simulate coupled processes in complex and heterogeneous reservoir models. With the appropriate extension, flow diagnostics could also be used to screen and assess the impact of hydro-mechanical processes on reservoir performance so as to select a smaller number of models for detailed, and computationally costly, fully coupled hydro-mechanical simulations. We hence present an approach that allows us to extend the existing flow diagnostics to account for geomechanical effects without increasing the computational overhead significantly. Flow diagnostics approximate the dynamic reservoir behaviour in seconds by computing the time of flight and steady-state tracer distributions directly on the reservoir grid. Hence, the extended flow diagnostics simulations complement full-physics simulations for estimating reservoir connectivity, fluid-fronts distributions, fluid displacement efficiency and well allocation factors under geomechanical effect. The acceleration of the proposed hydro-mechanical coupling is achieved by: 1) the representation of the dynamic behaviour through the use of flow diagnostics simulations (Møyner et al., 2014); 2) the formulation of the hydromechanical problem to account for steady-state conditions based on poro-elastic theory (Coussy, 1994, 2004); 3) a sequential stress-flow coupling using stress-dependent permeability as a coupling term. This coupling strategy ensures stability and fast convergence of the hydro-mechanical solution using a stress-fixed split strategy (Kim et al., 2011a, 2011b) and yields a significant reduction of the CPU time. Two cases studies were analysed based on the SPE 10 Model (Christie and Blunt, 2001) in which the effect of a 5-spot injection pattern subjected to a gravity load is studied, and the effect of mechanical heterogeneity is considered. These examples demonstrate the application of the proposed methodology to assess geomechanical impact in highly heterogeneous formations and the importance of not only account for petrophysical heterogeneities when assessing reservoir performance but also for the heterogeneity of mechanical properties as these alter the petrophysical properties when stress-sensitive reservoirs are produced. Geomechanically informed flow diagnostics account for coupled hydro-mechanical effects that can alter the performance of stress-sensitive reservoirs during production.

Naturally fractured reservoirs hold significant reserves but are highly heterogeneous and are challenging to simulate flow in. Dual Porosity (DP) methods, although widely used, require fine tuning using production data and thus lack predictive capability in green field applications. The Embedded Discrete Fracture Model (EDFM), which explicitly represents complex fracture network geometries at the cost of computational efficiency, is an excellent tool that can complement the DP method. Using EDFM, we study water coning phenomena in a green fractured Latin American gas field. We do this by simulating gas flow in a stochastically generated sector model representative of the field. EDFM simulations performed using different well rates revealed three possible flow regimes that the field may experience: stable flooding at low flow rates, coning with matrix production at moderate flow rates, and coning without matrix production at high flow rates. These results have implications in field development plans and can also be used for validating any DP models that may be used for full field simulations in the future. Through this study, we demonstrated how EDFM can be used, before any field production, to gain insights into the flow behaviour in a green field.

Naturally Fractured Reservoirs (NFR's) have received little attention as potential CO₂ storage sites. Two main facts deter from storage projects in fractured reservoirs: (1) CO₂ tends to be nonwetting in target formations and capillary forces will keep CO₂ in the fractures, which typically have low pore volume; and (2) the high conductivity of the fractures may lead to increased spatial spreading of the CO₂ plume. Numerical simulations are a powerful tool to understand the physics behind brine-CO₂ flow in NFR's. Dual-porosity models are typically used to simulate multiphase flow in fractured formations. However, existing dual-porosity models are based on crude approximations of the matrix-fracture fluid transfer processes and often fail to capture the dynamics of fluid exchange accurately. Therefore, more accurate transfer functions are needed in order to evaluate the CO₂ transfer to the matrix. This work presents an assessment of CO₂ storage potential in NFR's using dual-porosity models. We investigate the impact of a system of fractures on storage in a saline aquifer, by analyzing the time scales of brine drainage by CO₂ in the matrix blocks and the maximum CO₂ that can be stored in the rock matrix. A new model to estimate drainage time scales is developed and used in a transfer function for dual-porosity simulations. We then analyze how injection rates should be limited in order to avoid early spill of CO₂ (lost control of the plume) on a conceptual anticline model. Numerical simulations on the anticline show that naturally fractured reservoirs may be used to store CO₂.