The Kuqa Depression in the northern Tarim Basin, NW China, is characterized by fault-controlled anticlines where natural fractures may influence production. Natural fractures in the Lower Cretaceous tight sandstones in the depression have been studied using seismic profiles, borehole images, cores and thin-sections. Results show that thrust faults, two types of opening-mode macrofractures and two types of microfractures are present. Thrust faults were generated during Cenozoic N–S-directed tectonic shortening and have hydraulically linked Jurassic source rocks and Cretaceous sandstones. Opening-mode fractures can be subdivided on the basis of sizes, filling characteristics and distribution patterns. Type 1 macrofractures are barren or mainly calcite-lined. They have straight traces with widths (opening displacements) that are of the order of magnitude of 10 μm, suggesting that their primary role is that of migration channels. Type 2 macrofractures are calcite-filled opening-mode fractures. They have an elliptical or tabular shape with sharply tapering tips. Transgranular microfractures are lens-shaped and open or filled mostly by calcite; maximum widths range between 0.01 mm and 0.1 mm. Intragranular microfractures are the most common microfracture type. They are filled by calcite, feldspar or quartz. The macrofractures and transgranular microfractures have regular distributions, while most intragranular microfractures are irregularly distributed owing to their inherited origin. The results imply that natural fractures in the tight sandstones were formed as tectonic, diagenetic and natural hydraulic origins. In situ stress and cementation analyses suggest that Type 1 macrofractures and their genesis-related microfractures have controlled the present flow system of the tight sandstones.

Electrical borehole image logs have the potential for direct interpretation of lithofacies characteristics. The challenge is to establish a set of reliable diagnostic criteria with which electrical images can be correlated to lithofacies features such as lithology, sedimentary structures, and bedding sequences. We used the “behind-outcrop” logging procedure that can link borehole images to actual rocks and also reduce errors that are associated with core-shift process. To better reveal the correlation between borehole images and carbonate lithofacies for subsurface reservoir applications, and also make a comparative petrographic analysis with the aim of establishing diagnostic criteria for borehole images, a 200 m well was drilled in the Tarim Ordovician outcrop. A full set of borehole image data and cores with approximately 100% coring recovery rate was acquired at the same depth interval, and more than 100 stained thin sections were prepared. Electrical borehole images in wells adjacent to the outcrop were further interpreted to validate the proposed criteria. Borehole image electrofacies were established according to the image elements, such as stacked mode, bed thickness, conglomerate diameter, rim characteristics, and internal structure of bed/conglomerate, to interpret depositional/diagenetic textures and platform-slope associations. Nine image electrofacies types, corresponding to mud/wacke/pack/grain/bindstone texture, were identified and interpreted in detail. Our method reveals a set of diagnostic criteria for borehole image interpretation in carbonate platform slope, and it finally provides a powerful tool for direct interpretation of electrical images in similar reservoir environment.

Automatic bedding extraction from borehole images of shale beddings and cross beddings is essential for reducing labor-intensive manual tasks. Three main types of algorithms, including Autodip, Random Hough Transform (RHT), and Pairing Algorithm Based Detection (PABD), have been proposed in the past decades but have never been directly compared. In this study, we first propose a novel method integrating a heuristic genetic algorithm (Autodip integrate with Genetic Algorithm, ADGA) to overcome the low efficiency of the Autodip algorithm. This method improves the efficiency by a factor of 3, and even by a factor of 21 with the addition of automatic constraints, while maintaining the advantages of high accuracy. Furthermore, to verify the effectiveness of the improved algorithm, all extraction algorithms are compared and analyzed systematically for the first time. The results demonstrate that three algorithms have presented their unique advantages and adaptability. The ADGA has the best stability, extraction accuracy, and image fitness for shale beddings. The PBAD algorithm shows its superiority in cross-bedding. The RHT has the best efficiency with moderate stability. In addition, the extraction results produced by RHT are of poor quality for images with high density and low amplitude bedding (less than about 10 pixels) due to the inadequate performance of the structure tensor image processing. This research will significantly promote the future development of automatic bedding extraction algorithms for industrial applications.

Natural fractures are pervasive in southern Sichuan Basin marine shales, China, and provide a useful opportunity to try to understand subsurface fracture networks in shale reservoirs. Based on cores and electrical imaging logs from vertical and horizontal petroleum wells in the southern Sichuan Basin, four types of natural fractures were identified in terms of orientation, size, filling properties and spatial distribution. Uncemented bed-parallel shear fractures develop at or in the vicinity of mechanical interfaces and are inclined to present in shale layers with a dip angle greater than 12°. Cemented bed-parallel fractures are characterized by a crack-seal texture marked by multiple bands of fibrous cement, and their intensity decreases upwards and shows a positive relationship with total organic carbon (TOC) values. Uncemented bed-oblique fractures are a type of fracture that rarely develops, and accommodate limited open space. Cemented bed-oblique/perpendicular fractures are the most developed fracture type and are distributed on a regional scale and are subdivided into two types. The results imply that these shale fractures could be formed sequentially by local and regional tectonic deformation, and by abnormally high pressure. Most natural fractures cannot contribute to reservoir storage or efficiently enhance its permeability, yet can act as planes of weakness and be potentially reactivated during hydraulic fracture treatments.