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.@en

Spontaneous countercurrent imbibition into a finite porous medium is an important physical mechanism for many applications, included but not limited to irrigation, CO2 storage, and oil recovery. Symmetry considerations that are often valid in fractured porous media allow us to study the process in a one-dimensional domain. In 1-D, for incompressible fluids and homogeneous rocks, the onset of imbibition can be captured by self-similar solutions and the imbibed volume scales with √t. At later times, the imbibition rate decreases and the finite size of the medium has to be taken into account. This requires numerical solutions. Here we present a new approach to approximate the whole imbibition process semianalytically. The onset is captured by a semianalytical solution. We also provide an a priori estimate of the time until which the imbibed volume scales with √t. This time is significantly longer than the time it takes until the imbibition front reaches the model boundary. The remainder of the imbibition process is obtained from a self-similarity solution. We test our approach against numerical solutions that employ parametrizations relevant for oil recovery and CO2 sequestration. We show that this concept improves common first-order approaches that heavily underestimate early-time behavior and note that it can be readily included into dual-porosity models.@en

Naturally fractured reservoirs (NFRs) account for a significant amount of the world conventional reserves but suffer from low recovery factors. Multiple techniques are, often in combination, used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the use of dual-porosity model for analysis of well test data in order to identify and interpret the behaviour of fluid flow in NFR. This model, originally developed by Warren & Root (1963), has since been the industry standard for modelling NFRs and interpreting well-test data from NFRs. However, several studies have shown that the dual-porosity responses expected for naturally fractured reservoirs are not always observed where the wellbore intersect fractures, even for heavily and well-connected fractured network reservoirs. Our research aims to examine the reservoir features that cause the dual-porosity response to absent in some naturally fractured reservoirs and to be present in others. We demonstrate when dual porosity models are valid for well-test interpretation and can capture the key reservoirs features that characterise flow behaviours in NFRs. These features include the effect of fracture skin, network connectivity, and network size. The findings allow us to interpret well-tests in NFR more reliably.@en

Simulation of multiphase flow in fractured reservoirs still poses a challenge due to the different timescales of fluid flow in fractures and matrix. Common approaches to modeling fractures in reservoir simulators include the discrete fracture and matrix (DFM) method, where the fractures are explicitly represented as lower-dimensional elements in the computational mesh, and multicontinuum approaches (e.g., dual-porosity and dual-permeability models) where the behavior of the fractures and matrix are integrated and treated as distinct continua. The latter requires models (bespoke “transfer functions”) that upscale the multiphase transfer between fracture and matrix. There are several formulations for transfer functions available in the literature, and they are often application dependent. Here, we propose a unified framework for simulation of flow in fractured media. The framework makes no distinction between dual-continuum and DFM methods, treating fractures and one or more matrix domains as flowing domains and virtual domains. Transfer functions are reinterpreted as fluxes between cells of different domains. This enables us to create an abstraction that encompasses both methods and makes it easy to build hybridized models including different regions with different matrix/fracture interaction concepts. We present a series of cases to illustrate the main differences between both modeling approaches and the benefit of a flexible implementation that enables the development of a fit-for-purpose simulator for fractured reservoirs.@en

Naturally fractured reservoirs are currently being considered as potential candidates for geological storage of CO2. Simulations of fractured reservoirs are notoriously challenging. Dual-porosity models are a cost-effective way of representing fractured reservoirs whose fundamental ingredient are transfer functions that represent fracture-matrix interaction in an up-scaled manner. In order to develop accurate transfer functions, it is essential to capture the underlying physics of the fluid transfer. Material properties and dominant processes in CO2 storage differ from the ones in conventional production environments. In this contribution we develop a novel transfer function that accounts for these differences. We first analyse the simplifying hypotheses that are commonly made in the current existing transfer functions. Those simplifications lead to inaccurate results in the context of CO2 storage. We then develop a transfer function for buoyancy displacement based on the timescale of the one-dimensional equation for immiscible two-phase flow in porous media. We analyse how the newly developed transfer functions improve over the current existing ones in simple matrix-block geometries. The results are evaluated against high-resolution numerical simulations of matrix blocks considering realistic physical properties of CO2/Brine systems and fractured rocks. Our results show that the developed transfer functions are able to represent accurately the basic physics of the process, and improve over other existing transfer functions in the literature. The transfer functions are also implemented in a dual-porosity simulator and different CO2 injection scenarios are tested. We show that a careful design of the injection schedule may increase the mass of CO2 that is stored in the matrix block.@en

Geological reservoirs can be extensively fractured but the well-test signatures observed in the wells may not show a pressure transient response that is representative of naturally fractured reservoirs (NFRs): for example, one that indicates two distinct pore systems (i.e. the mobile fractures and immobile matrix). Yet, the production behaviour may still be influenced by these fractures. To improve the exploitation of hydrocarbons from NFRs, we therefore need to improve our understanding of fluid-flow behaviour in fractures. Multiple techniques are used to detect the presence and extent of fractures in a reservoir. Of particular interest to this work is the analysis of well-test data in order to interpret the flow behaviour in an NFR. An important concept for interpreting well-test data from an NFR is the theory of dual-porosity model. However, several studies pointed out that the dual-porosity model may not be appropriate for interpreting well tests from all fractured reservoirs. This paper therefore uses geological well-testing insights to explore the limitations of the characteristic flow behaviour inherent to the dual-porosity model in interpreting well-test data from Type II and III NFRs of Nelson’s classification. To achieve this, we apply a geoengineering workflow with discrete fracture matrix (DFM) modelling techniques and unstructured-grid reservoir simulations to generate synthetic pressure transient data in both idealized fracture geometries and real fracture networks mapped in an outcrop of the Jandaira Formation. We also present key reservoir features that account for the classic V-shape pressure derivative response in NFRs. These include effects of fracture skin, a very tight matrix permeability and wells intersecting a minor, unconnected fracture close to a large fracture or fracture network. Our findings apply to both connected and disconnected fracture networks.@en