Modelling the transient effect in naturally fractured reservoirs

Abstract

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.

The Impact of Contact Area and Fracture Surface Roughness on Fluid Flow in Fractured Reservoirs

“…The above steps could be applied to any fracture network to estimate the reduction in fracture permeability due to the sealed aperture by cementation or any other reasons, which should be supported by outcrop or sedimentology studies. Moreover, the same procedure has been applied to the 2D models and 3D single aperture models except for step (2), where a single value of aperture was assigned. In addition to using Sequential Indicator Simulation (SIS) or Truncated Gaussian Simulation (TGS) approaches to distribute the zero aperture cells randomly.…”

“…Naturally fractured reservoirs are highly heterogeneous systems, where fractures control the reservoir permeability, and hence the fluid flow behaviour [1,2,3,4]. Therefore, accurate modelling of the fracture network has a key role in the development of such complicated reservoirs [5,6,7].…”

Discrete fracture modeling by integrating image logs, seismic attributes, and production data: a case study from Ilam and Sarvak Formations, Danan Oilfield, southwest of Iran

“…Seismic data generally cannot resolve individual fractures but simply gives an indication of the presence and orientation of fracture sets (Pérez et al 1999;Protasov et al 2016;Pan et al 2021). On the other hand, the basic suite of well-logs typically recorded post-drilling is not able to resolve fractures, identify whether fractures present are open, or distinguish fracture porosity from matrix porosity (Mohebbi et al 2007;Bahrami et al 2012;Sun et al 2014;Mazaheri et al 2015;Aljuboori et al 2022). Whole wellbore cores, if recovery is high, tend to provide good material for fracture identification and measurements (Khoshbakht et al 2012).…”