The largest Precambrian gas field in China has been found in the central Sichuan Basin. It is assumed as a mound-shoal microfacies-controlled dolomite reservoir. Recently, a large strike-slip fault system has been identified in the gas field that needs further study of its effect on the Ediacaran reservoirs for highly efficient exploitation of the gas field. For this contribution, we study the matrix reservoir and fractured reservoir along the strike-slip fault damage zones by the cores, FMI (Formation MicroScanner Image) and logging interpretation data, seismic description and production data. It has shown that the matrix reservoir is tight (porosity less than 3%, permeability less than 0.5 mD) that cannot support economical production by conventional exploitation technology in the deep subsurface. On the other hand, the porosity and permeability of the Ediacaran fractured reservoirs could be increased more than one time and 1–3 orders of magnitude. Except for a few localized fracture zones, the fracture elements and fractured reservoirs show a paw-law distribution with the distance to the fault core. Furthermore, the fault effect is more favorable for the increase in the porosity and permeability of the matrix reservoir in the intraplatform than in the platform margin. The overlapping of mound-shoal microfacies, fracturing and karstification could result in large-scale “sweet spots” of the fractured reservoirs in the fault damage zone. The “sweet spot” of fractured reservoir in the fault damage zone is a new favorable exploitation target in the deep central Sichuan Basin.

Lower Triassic Feixianguan oolithic shoal complexes are widely developed in the northwestern Sichuan Basin, southwest China, where they host large natural gas reserves. To understand their development and the factors that controlled their deposition, we have used observations and interpretations of outcrops, cores, thin sections, well-log data, and seismic data to characterize the geologic and geophysical properties of the oolithic shoals of the Lower Triassic Feixianguan Formation in the Jiange area, northwestern Sichuan Basin. The oolithic shoals of the Feixianguan Formation are composed of locally dolomitized oolithic grainstones or packstones deposited in a semirestricted platform environment. With a thickness of more than 50 m, oolithic shoals mainly occur in the Fei 2 Member within the southeastern Jiange area. The results indicate that the shoals mainly lie above tectonic uplifts (caused by the northwest-trending basement-involved faults) and surrounding microtopographic highs. Furthermore, the prograding clinoforms and changes in accommodation space caused by sea-level fall influence the thickness of oolithic shoal deposits, and constrain their development in highstand systems tracts, resulting in their migration coinciding with the trend of clinoform progradation. We concluded that the development of oolithic shoals in the Jiange area may be controlled by two major factors: (1) the influence of paleotopography governed by the syndepositional faults on the accumulation of oolithic shoals and (2) the role of sea-level change in the migration of oolithic shoals.

Understanding the influence of strike–slip faulting on deep carbonate reservoirs remains challenging. This study integrates core observations, well logging, and seismic interpretation to investigate fracture diagenesis and evaluate the impact of strike–slip faulting on Upper Permian reef–shoal reservoirs in the northern Sichuan Basin. Within the platform margin reef–shoal microfacies, transtensional faulting during the Late Permian was later overprinted by transpressional deformation in the Early–Middle Triassic. Although individual fault displacements are generally less than 200 m, the associated damage zones may extend over 1000 m in width. Strong compaction and cementation eliminated most primary porosity in the reef–shoal carbonates, whereas dissolution enhanced porosity preferentially developed along fault damage zones. The most productive of fracture–vug reservoirs (“sweet spots”) are mainly distributed adjacent to strike–slip fault zones within the reef–shoal bodies. Reservoir quality is controlled by syn-sedimentary faults, moldic vugs, karstic argillaceous fills, and U-Pb ages of fracture cements that indicate multi-stage diagenesis. Contemporaneous fracturing and dissolution during the Late Permian played a dominant role in enhancing reservoir porosity, while burial-stage cementation had a detrimental effect. This case study demonstrates that even small-scale strike–slip faulting can significantly improve reservoir quality in deep tight reef–shoal carbonates.

The Lianggaoshan Formation in the Gongshanmiao block of the Sichuan Basin is characterized by narrow channel sand bodies and thin layers, resulting in weak seismic responses, which leads to poor identification of small-scale fault–fracture systems. Initial high-density 3D seismic data exhibit strong shallow surface waves and significant shot-to-shot variations in energy and frequency, necessitating amplitude-preserving noise attenuation and broadband wavelet consistency processing. First, pre-stack multi-domain amplitude-preserving noise attenuation is applied, integrating surface-wave forward modeling, stationary wavelet transform, and matrix singular value decomposition to suppress complex noise. Next, robust deconvolution constrained by a target wavelet improves broadband consistency. Subsequently, anisotropic depth-domain velocity modeling and imaging under rugged topography are conducted using a well-constrained TTI initial velocity model and full-azimuth angle-domain grid tomography. Compared with conventional data, the processed high-density data significantly enhance bandwidth, structural imaging, and thin-layer resolution. Imaging continuity of small faults (6–10 m throw) is markedly improved, and the channel characterization accuracy of the Liang-2 Member increases from 180 m to 60 m. This workflow delivers high-SNR, high-resolution, and high-fidelity results, providing a reliable basis for thin-sandbody prediction and reservoir evaluation.

The Sinian Dengying Formation reservoirs in the Anyue Gas Field, Sichuan Basin, exhibit extreme heterogeneity. The existing karst geomorphological classification is too coarse to account for the significant differences in high-quality reservoir scale and productivity observed among adjacent wells within the same third- to fourth-order karst geomorphic units. To accurately predict the distribution of high-quality reservoirs, it is essential to reveal the precise mechanisms by which low-order micro-geomorphology controls paleokarstification and reservoir development. Based on 3D seismic data, core samples, thin sections, Formation MicroScanner (FMI) images, and geochemical analysis of data from the Gaoshiti–Moxi area, this study investigates how various micro-geomorphic units control karstification from both macroscopic and microscopic perspectives and subsequently analyzes their reservoir-controlling mechanisms. The results indicate the following: (1) The paleogeomorphology at the top of the Dengying Formation was restored using the impression method with a decompaction correction. A classification standard for micro-geomorphology at the top of the fourth member of the Dengying Formation (Z₂dn⁴) dolostone was established, identifying ten micro-geomorphic units, including coastal plains, river channels, and terraces. (2) Micro-geomorphic morphology dictates the distribution of the paleokarst hydrodynamic field, thereby controlling the intensity of karstification. River channels, terraces, and coastal plains, characterized by strong hydrodynamics, are the most favorable micro-geomorphic units. Inclined plains, with moderate hydrodynamics, are secondary favorable units. Conversely, concave plains and karst hills, with weak hydrodynamics and slow water alternation, are unfavorable units. (3) Six models of high-quality reservoir development, dominated by micro-geomorphic units in both intra-platform and platform-margin settings, were constructed, emphasizing the multi-element coupling of “strong karstification–40%–60% microfacies–faults”. This study reveals that micro-geomorphology is the key factor controlling the development of Z₂dn⁴ karst reservoirs. Predicting sweet spots by superimposing sedimentary facies and fault distributions onto micro-geomorphic maps can effectively improve the drilling success rate and development efficiency of deep carbonate reservoirs.

With the increasing exploration and development of deep (>4500 m) hydrocarbon resources, fault-controlled reservoirs have become important sweet-spot targets in deeply buried tight rocks. However, it remains challenging to decipher the coupled relationships among deformation, fluid flow, diagenesis, and reservoir evolution within fault damage zones. In this review, we synthesize recent advances, including contributions to this Special Issue, on deformation, diagenesis, and reservoir development within fault damage zones in sedimentary basins. Fault-zone architecture commonly comprises a narrow fault core and a wider damage zone, with fault cores supported by particles, matrix, or cement, and damage zones characterized by outward-decreasing deformation intensity and fracture network complexity. Although fracture intensity, porosity, and permeability commonly follow a power-law decrease with increasing distance from the fault core, these parameters are highly scattered because they are jointly controlled by complex structural and diagenetic overprinting. Non-Andersonian fault-tip propagation, fault interaction, linkage, and reactivation play key roles in the development of wide and heterogeneous fracture zones. During progressive burial, mechanical compaction and cementation generally reduce primary porosity, whereas dissolution may generate or enhance secondary pore systems. Hydrothermal dissolution can locally improve reservoir quality, whereas mineral precipitation commonly occludes pores and fractures and reduces permeability. Except for the high-energy microfacies, the coupling between fracturing and contemporaneous, burial-related, or supergene dissolution is critical for the formation and preservation of secondary reservoirs. Integrated faulting period analysis and U-Pb dating of carbonate cements within fractures provide an effective approach for reconstructing the timing of fracturing, fluid flow, and diagenetic modification. In sedimentary basins, heterogeneous fractured reservoirs are unevenly distributed along fault damage zones. Their formation is controlled by the complex coupling of lithology, structural deformation, fluid flow, and diagenesis. Therefore, the key scientific challenge is to quantitatively characterize the spatio-temporal evolution and coupling mechanisms of deformation, diagenesis and fluid flow control on reservoir properties within fault damage zones. Ultimately, this review provides a novel, time-resolved framework for predicting deep sweet-spot reservoirs, shifting the paradigm from purely structural description to quantitative structural–diagenetic modeling.