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In Naturally Fractured Reservoirs (NFR) diffuse fractures arrangement results from mechanical stratigraphy and tectonic history during failure. Thus, modelling Discrete Fracture Network (DFN) requires to understand and to account for fracture relationships at bed-interface (abutment or crosscutting) in 3D through time (loading path). However, sampling fractures data meaningfully in subsurface has always been a challenge for geologist due to data scarcity. To better understand and forecast fracture networks in stratified rocks, we study outcrops with a focus on geometric relationships between stratigraphic interfaces and fractures. This paper presents an original python toolbox called FracAbut. It is composed of 1 main and 2 auxiliary codes that quantify the geometric relation between fractures and stratigraphic interfaces from 1D (wells, scan-line) and 2D (digital image, photographs data). We calculate the Interface Impedance (II) that accounts for fracture abutment (crossing or not), persistence (single- or multi-bed) and propagation polarity (upward or downward). For each stratigraphic interface FracAbut provides information on fractures (type, number) and interface sensitivity (coupling strength). First, we apply FracAbut on synthetic case studies, then, on naturally fractured and stratified carbonates in Berat, Albania. Using both 1D scan-line and 2D outcrop photograph, we show that i) a mechanical interface can have different coupling above and below based on propagation polarity, ii) FracAbut results can give useful insight on fracture transmissivity, iii) FracAbut is fast and efficient to quantify fracture patterns and classify mechanical interface impact; iv) they are no relation between bed thickness and fracture propagation. • Quantify the impact of mechanical stratigraphy on fracture propagation. • FracAbut is dedicated to process 1D or 2D fracture and bed interface surveys. • Interfaces are characterized based on fractures persistence and abutment. [ABSTRACT FROM AUTHOR]

The parameters of fractures, such as fracture geometries, placement, and conductivity, are critical for the production of horizontal wells in tight gas reservoirs. Current studies on fracture parameter optimization, especially those using the optimization algorithms, are often based on the assumptions that the fractures are uniformly placed with equal length and conductivity. However, non-uniform designs of fracture spacing have been proved to be effective in reducing fracture interference as well as increasing the well production, especially with strong rock heterogeneity. In addition, most of the current literature focuses on identifying optimal hydraulic fracture geometries without considering the fracture propagation process, which may oversimplify the evaluation of completion cost and result in fracture geometries that cannot be realized in practice. In this paper, an automatic optimization process, which could efficiently couple the fracture propagation, is proposed to optimize the fracture parameters. The genetic algorithm (GA) with penalty function method is used to optimize the constraint and non-linear problem. A modified PKN fracture propagation model is established to quickly predict the hydraulic fracture geometries. Fracture locations and fluid injection volume are sequentially optimized with consideration of heterogeneous rock properties. Model parameters are taken from typical tight gas horizontal wells in Jinqiu gas field in Sichuan Province, China. The results show the importance of permeability on both fracture length and production in tight gas well. The lower the permeability, the more significant the production increase after fracture location optimization. More fractures tend to be placed in area with small permeability and fewer fractures are required in highly permeable regions. With an increase in rock heterogeneity, the distribution of fractures becomes more uneven. Conversely, increasing the number of fractures can lead to a more even distribution of fractures. More fluid should be injected in low-permeability regions according to the optimization results. The optimization method is applied to a practical tight gas well in Sichuan Basin and the cumulative gas production can be increased by 6.5% to 8% when compared with the initial uniform designs. • A modified PKN model is proposed for quick prediction of fracture propagation, validated against numerical simulations. • GA is used to optimize fracture locations by considering rock heterogeneity's impact on fracture propagation and production. • Sequential optimization of fracture placement and injection volume is conducted with its reliability verified. [ABSTRACT FROM AUTHOR]