The Upper Triassic Yanchang Formation in the Ordos Basin, central China, is a typical sandstone reservoir with an ultra-low permeability. High-angle tectonic fractures and diagenetic fractures, such as near-horizontal bedding fractures, intragranular fractures, and grain-boundary fractures, are abundant. Fractures are major pathways and enhance fluid flow in sandstone reservoirs with ultra-low permeability. Because of their weak lateral continuity and their small apertures under lithostatic pressure, bedding fractures make a relatively small contribution to the overall permeability of reservoirs. As they are both of small size and low permeability, intragranular fractures and grain-boundary fractures mainly improve the connectivity of reservoirs by connecting the matrix pores. High-angle tectonic fractures control the fluid movement in the ultra-low-permeability reservoirs. Under the effect of different successive tectonic stress fields, four assemblages of high-angle tectonic fractures developed in the sandstone reservoirs. Under the present-day stress, differently oriented fractures have different connectivities, apertures, and permeabilities. The northeast–southwest fractures parallel to the maximum principal stress have a good connectivity, large apertures, and a high permeability, forming the dominant flow paths. Knowledge of these paths can be used for optimizing well placement. Because of their sensitivity to pressure, fractures in different directions will show varying apertures as the formation pressure decreases. Therefore, the permeability of the fractures of different orientations and its impact on reservoirs vary at different developmental stages.

Although conventional reservoirs dominate the Bohai Basin, China, a new type of sandstone reservoir also exists in the Dongpu depression that has a low matrix porosity (tight) in which natural fractures govern both permeability and porosity. These fractured sandstones are located on a structurally modified buried hill underlying Paleogene mudstones, and are truncated along an angular unconformity. The fractured sandstone oils of the Triassic Liujiagou, Heshanggou, and Ermaying Formations are derived from the Paleogene Shahejie Formation, which reached peak oil generation and expulsion during the Oligocene to early Miocene (32.8–15.6 Ma). Gas was generated primarily during the Paleogene from Carboniferous and Permian coals. Petrographic evidence suggests that oil and gas emplacement followed the compaction and cementation of the Triassic sandstone reservoirs. Fluid inclusion evidence and burial history analysis suggest that fractures developed before oil emplacement but may have coincided with peak gas generation, which suggests that oil and gas mainly migrated and accumulated in fractures.

The western Sichuan Basin located at the front of the Longmen Mountain in the western Sichuan Province of China is a foreland basin formed in the Late Triassic. The Upper Triassic Xujiahe Formation in the basin is an ultralow-permeability and low-porosity tight-gas sandstone reservoir. Microfractures, such as intragranular microfractures, grain-edge microfractures, and transgranular microfractures, are abundant in the tight sandstones. Microfractures improve storage and permeability and impact distribution of natural gas. Microfractures reflect tectonic, overpressure, and diagenetic origins. Using quartz and calcite fluid inclusions and burial history, tectonic microfractures were determined to be formed at the end of the Triassic, the end of the Cretaceous, and the end of the Neogene–early Pleistocene. Microfractures related to overpressure, being tension microfractures, are commonly filled with bitumen and were formed at the middle to Late Cretaceous when the maximum pressure coefficients were 1.6 to 2.1. In the middle to late Neogene, the pressure coefficient was reduced to less than 1.3 because of fault activity and tectonic uplift in the southwestern Sichuan Basin, and these tension microfractures closed and were filled with calcite. The transition of stress state from compression to tension by overpressure is the reason that tension microfractures were formed in the compression setting. Diagenetic fractures were formed at the end of the Late Triassic to Jurassic. Under intense compaction, grain-crushing crackle fractures in quartz and cleavage fractures in feldspar formed intragranular microfractures. Some transgranular microfractures caused by diagenesis are along the bedding plane and parallel to the directional mineral grains.

Fractures are the main fluid-flow pathways in tight-oil sandstones, and they have a significant influence on tight-oil distribution, exploration, and development. Cores and image logs are commonly unavailable because of their high costs, so employing conventional logs for fracture detection is imperative for tight-oil sandstones. We compared the fracture-response characteristics of conventional logs based on two data sets, one from 8 cored wells with fracture intensities greater than 1 m−1 (3.3 ft−1) and the other from 11 cored wells with fracture intensities less than 0.5 m−1 (1.6 ft−1), with a case study of the Upper Triassic Yanchang Formation in southwest Ordos Basin, China. The results indicate that when tight-oil sandstones are more intensely fractured, the caliper log, acoustic log, compensated neutron log, density log, dual induction logs, and laterolog 8 present fracture responses to some extent. However, it is difficult to make a distinction between fractured and nonfractured zones using conventional logs in sandstones with smaller fracture intensities. The fracture-response intensities of conventional logs are weak, and they are influenced by fracture abundance, fracture occurrence, fracture scale, and mineral-filling degree. Moreover, lithology, fluids, and rock physical properties can cause fracturelike responses. Hence, some ambiguity exists when using conventional logs to directly identify fractures. Accompanying fracture-sensitive conventional logs with some methods to enhance fracture-response intensity and eliminate nonfracture influence could enable fracture identification in tight-oil sandstones.

Paleogene saline lacustrine carbonate rocks are important fractured reservoirs in the western Qaidam Basin. Core data show that most fractures are small, steeply dipping faults; bedding-plane slip faults; and subvertical opening-mode fractures. Other fractures are diagenetic in origin. Fracture occurrence and abundance patterns are controlled by lithology, bed thickness, and proximity to larger faults. Fractures are generally filled with calcite, gypsum, or glauberite (Na2Ca[SO4]2); the degree of fracture filling determines the effectiveness of fractures as fluid conduits and the distribution of high-quality reservoirs. Open fractures not only provide the main pathways for fluid flow, but also enhance the free fluid index and the free fluid saturation measured by nuclear magnetic resonance and determine the potential production rates of tight carbonate reservoirs. The open fractures are parallel to and occur near faults, and many do not coincide with the present-day direction of the maximum horizontal compressive stress.