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Modelling of Naturally Fractured Reservoirs (NFR's) is a very challenging task. NFR's are often simulated using the dual-porosity (DP) model, which requires significantly lower computational time and less simulation cost compared with the fine-grid modelling. However, the DP model is unable to capture the transient effect, the saturation front, and its tendency to overestimate the predicted oil recovery, as the invaded fluid is immediately reaching the gridblock centre once its saturation exceeds the critical saturation. The matrix block discretisation and modifying the transfer function are among the widely investigated areas to represent the transient effect and to improve the simulation accuracy. Adjusting the transfer function often results in complicated and unstable solutions, which make this approach limited in use. However, the matrix discretisation technique, such as Multiple Interacting Continua (MINC), is one of the utilised approaches to improve the simulation of NFR's. The model's layers provide the required mean to capture the transient effect and to include the matrix heterogeneities. In this work, we present an improvement to the original MINC model to enhance its accuracy and stability using a particular case of two subdomains model. We suggested using an equal volume of the matrix sub-blocks, besides performing an adjustment to the calculation of fluid saturation. The new adjustments have provided a stable solution and improved simulation results compared with the original MINC model. Besides the advantage of the matrix layers to handle various heterogeneities with excellent simulation accuracy and marginal errors, and hence a reliable performance and prediction. [ABSTRACT FROM AUTHOR]

Permeability is an essential parameter for the reservoir characteristics, which controls the flowing fluids in the reservoir hence the sweep efficiency and the ultimate recovery. The common practice in the petroleum industry is coring a limited number of wells, due to the expensive core recovery process, and measuring the permeability in the recovered cores then extend the concluded correlation to the un-cored wells. However, establishing a reliable permeability predictor is not an easy task in many heterogeneous formations due to the spatial variability of the permeability even at very close distances. Therefore, the conventional linear regression has often failed to address the formation’s heterogeneity, and an unsatisfied correlation coefficient has frequently obtained. Lower Qamchuqa formation, which is highly prolific producing formation in the Middle East, has been used as an example of highly heterogeneous carbonate systems. Well log measurements, which are available for most of the wells, in addition to the core data, were used to capture the high heterogeneity of the depositional environment. Core-log depth calibration was first performed to extract the accurate log measurements that correspond to the actual core data depth. Then, both core and log data were listed in a table for the statistical analysis using the neural network (NN) and multivariate regression approaches. A remarkable improvement in the correlation coefficient was obtained using the NN approach. The utilised training data and further verified by the validation data set have obtained a favourable accuracy compared with conventional linear regression or multivariate regression. The NN permeability predictor has proven its ability to overcome the complexity of the carbonate rock textures and the variety of the diagenesis alteration processes, which make the NN approach a superior method in obtaining an improved permeability predictor. Nevertheless, a regular update to estimate the permeability predictor would be necessary when new data acquired. [ABSTRACT FROM AUTHOR]

Naturally fractured carbonate reservoirs are often described as very heterogeneous systems due to the carbonate depositional environment and to the subsequent diagenesis processes such as mineral precipitation in fractures. Fluid flow behaviour in fractures is highly influenced by the fracture aperture size and its morphology. Mineral precipitation can alter the fracture effectiveness to the fluid flow and cause a partial or entire blockage of fractures. Therefore, accurate characterisation of the fracture morphology can help to enhance the prediction of the fluid flow behaviour in naturally fractured carbonate reservoirs. Mineral precipitation on fracture walls can reduce the fracture aperture significantly. As a result, the fracture permeability affected notably, which reduces the flow potential through fractures as well as changes the flow pattern. The objective of this work is to predict the flow behaviour in fractures under various levels of mineral precipitation to mimic reality. We have approached this objective by using outcrop-based models supported by a set of rock and fluid properties of a nearby fractured formation. Then, the model tested for the gas flow using the derivative plot technique of the synthetic well testing data. The simulation results have shown that mineral cementation can cause a partial blockage in fractures, hence a reduction in their flow capacity, as fractures become a less conductive medium. Nevertheless, the matrix medium can enhance the fluid flow in fractures by providing a bypass path to the fluid to overcome the sealed fractures. In this work, a formula has concluded to estimate the reduction in fracture permeability based on the fraction of the precipitated cement. In the studied formation, the core description has shown that 34% of fractures were blocked, which can lead to a reduction in the permeability by 29–64% and by 37–83% with and without matrix contribution, respectively. Thus, including the fracture morphology in the simulation model enables us to predict the performance of fractured carbonate reservoirs accurately. [ABSTRACT FROM AUTHOR]

Carbonate reservoirs in the Middle East hold a significant proportion of the remaining conventional oil reserves, which most of them were classified as naturally fractured. These reservoirs are well known for their low recoveries compared with their counterpart clastic unfractured reservoirs. Therefore, boosting their recoveries can assure to sustain the energy supply to the global oil markets. In this work, an example from the Middle East has been used to evaluate the impact of the fracture characteristics on the reservoir performance using four decades of production history. The characteristics of natural fractures have a remarkable impact on fluid flow behaviour in fractured reservoirs. Besides, these characteristics, such as fracture intensity, determines the matrix block dimensions, which in turn, influence the matrix recovery. However, it is challenging to estimate the fracture characteristics accurately due to the scarcity of the fracture data from subsurface measurements. Therefore, outcrop analogue data can be utilised to enhance the fracture modelling in fractured reservoirs and to fill the data gap between the seismic scale and well scale. In this work, we have integrated the outcrop fracture data with the core observations to improve the fracture modelling in the studied reservoir. Furthermore, a sensitivity study was carried out to investigate the impact of flow curves, gravity drainage mechanism, and its parameters, as well as the fracture storativity on the history matching in fractured reservoirs. Excellent matching results were obtained for the majority of the wells, as indicated by the low mismatch values. The obtained results highlighted the importance of fractures on the fluid flow behaviour, and hence the reservoir performance. Therefore, fracture properties should not be abusively modified using multipliers and local adjustment to avoid nullifying the reservoir characterisation efforts and degrade the simulation model capability for a future prediction. [ABSTRACT FROM AUTHOR]

Low salinity waterflooding is an effective technique to accelerate and boost oil recovery. The impact of this technique has been investigated widely in laboratories for various scales and rock typing, most of which have demonstrated a potential improvement in oil recovery. This improvement has been attributed to several chemical and physical interactions that led to a change in the wettability to become more water-wet, as well as a reduction in the residual oil saturation. Meanwhile, it is rare to find a discussion in the literature about the efficiency of low salinity flooding in naturally fractured reservoirs. Therefore, in this work, we investigate the potential advantages of this method in fractured reservoirs using numerical simulations. A new approach to estimate the weighting factor using a tracer model has been proposed to determine the brine salinity and, hence, its properties in the mixing region. We have also used the relative permeability curves as a proxy for any physical and chemical mechanisms which are not represented explicitly in the model. The simulation outcomes highlighted the advantage of low salinity waterflooding in fractured reservoirs. An increment in oil recovery by 10.7% to 13% of Stock Tank Oil Initially In Place (STOIIP) was obtained using the dual- and single-porosity model, respectively. Therefore, the low salinity waterflooding technique represents a promising low-cost, effective method in fractured reservoirs. [ABSTRACT FROM AUTHOR]

Gravity drainage is one of the essential recovery mechanisms in naturally fractured reservoirs. Several mathematical formulas have been proposed to simulate the drainage process using the dual-porosity model. Nevertheless, they were varied in their abilities to capture the real saturation profiles and recovery speed in the reservoir. Therefore, understanding each mathematical model can help in deciding the best gravity model that suits each reservoir case. Real field data from a naturally fractured carbonate reservoir from the Middle East have used to examine the performance of various gravity equations. The reservoir represents a gas–oil system and has four decades of production history, which provided the required mean to evaluate the performance of each gravity model. The simulation outcomes demonstrated remarkable differences in the oil and gas saturation profile and in the oil recovery speed from the matrix blocks, which attributed to a different definition of the flow potential in the vertical direction. Moreover, a sensitivity study showed that some matrix parameters such as block height and vertical permeability exhibited a different behavior and effectiveness in each gravity model, which highlighted the associated uncertainty to the possible range that often used in the simulation. These parameters should be modelled accurately to avoid overestimation of the oil recovery from the matrix blocks, recovery speed, and to capture the advanced gas front in the oil zone. [ABSTRACT FROM AUTHOR]