Large quantities of gas resources have been found in the Paleo-Mesozoic carbonate rocks in the Sichuan Basin. However, many wells cannot obtain high production in deep low porosity-permeability reservoirs. For this contribution, we provide a steerable pyramid method for identifying the fault damage zone in the Kaijiang–Liangping platform margin, which is infeasible by conventional seismic methods. The results show that steerable pyramid processing could enhance the seismic fault imaging and a series of NW-trending strike-slip faults are found along the trend of the carbonate platform margin. The steerable pyramid attribute presents distinct vertical and horizontal boundaries of the fault damage zone, and heterogeneous intensity of an un-through-going damage zone. The width of the fault damage zone is generally varied in the range of 100–500 m, and could be increased to more than 1000 m in the fault overlap zone, intersection area, and fault tips. Further, the fault damage zone plays a constructive role in the high gas production in the deep tight carbonate reservoir. The results suggest the steerable pyramid method is favorable for identifying the weak strike-slip faults and their damage zone. The width of the fault damage zone is closely related to fault displacement, and the much wider damage zone is generally influenced by the fault overlapping and interaction. The fractured reservoirs in the fault damage zone could be a new favorable exploitation domain in the Sichuan Basin.

The Middle-Upper Cambrian Xixiangchi Formation in the Sichuan Basin is regarded as an important reservoir with great potential for hydrocarbon exploration. It is previously indicated that the Xixiangchi carbonates have experienced extensive dolomitization, however, the origin of dolomitizing fluids and the dolomitization mechanism still remain uncertain. In this study, a set of petrographic and geochemical examinations, including rare earth elements (REE) and isotopic (C, O, and Sr) compositions were used to trace the origins of dolomitizing fluids and associated diagenetic processes. The petrographic examination revealed three types of matrix dolomites (D1, D2, D3) and one cement saddle dolomite (SD). These phases have crystal size ranges of less than 30 μm (very fine to fine crystals, D1), 30–100 μm (fine to medium crystals, D2), 100–300 μm (medium to coarsely crystalline dolomite, D3), and 0.3–4 mm (fracture filling cements, SD), respectively. D1 is characterized by non to very weak luminescence, weakly negative Ce anomalies (Ce/Ce* = 0.84 ± 0.02), strongly negative Eu anomalies (Eu/Eu* = 0.65 ± 0.03), and high ⁸⁷Sr/⁸⁶Sr ratios (0.71062 ± 0.00122). In combination with δ¹³C (−1.5‰ ± 0.2‰) and δ¹⁸O (−9.7‰ ± 0.5‰) compositions, D1 is interpreted to be formed by penecontemporaneous dolomitization in the near-surface environment with seawater as the dolomitizing fluid. In contrast, D2 is characterized by intercrystalline pores, dirty crystal surfaces, similar δ¹³C (−1.4‰ ± 0.4‰) compositions but higher δ¹⁸O (−8.9‰ ± 0.7‰) compositions, and lower ⁸⁷Sr/⁸⁶Sr ratios (0.70992 ± 0.00035), similar Ce anomalies (Ce/Ce* = 0.87 ± 0.04) and higher Eu anomalies (Eu/Eu* = 0.85 ± 0.04). The coarser D2 is regarded to be formed by the post-penecontemporaneous seepage-reflux dolomitization or by recrystallization of D1 dolomite in a near-surface or shallow burial environment. D3 is distinguished by a cloudy core with clear rims, showing slightly higher Eu anomalies (Eu/Eu* = 0.88 ± 0.02) and similar Ce anomalies (Ce/Ce* = 0.88 ± 0.02) than those of D1 and D2. Combined with the δ¹⁸O compositions (−10.4‰ ± 0.4‰) and ⁸⁷Sr/⁸⁶Sr ratios (0.70989 ± 0.00048), D3 is thought to be formed by the overgrowth or recrystallization of D1 and D2 dolomites in a shallow to moderate burial environment. The fractures filling SD dolomite consists of nonplanar and much coarser crystals with undulatory extinctions and brighter red luminescence. The lower δ¹⁸O (−11.1‰ ± 0.3‰) compositions, lower negative Eu anomalies (Eu/Eu* = 0.70 ± 0.01) of SD than the matrix dolomites, and similar Ce anomalies (Ce/Ce* = 0.83 ± 0.01) are indicative of hydrothermal dolomitization, with possible fluids associated with the magma during the period of Emei taphrogenic movement. In addition, the ⁸⁷Sr/⁸⁶Sr ratios (0.70941 ± 0.00003) of SD suggest probable origin from the coeval seawater partially. Therefore, SD dolomite is interpreted to be formed by hydrothermal dolomitization with mixed dolomitizing fluid of seawater and hydrothermal fluids. In summary, all the matrix dolomites have almost the same ΣREE concentrations and exhibit similar near-flat REE partition patterns with weak LREE enrichments, weakly negative Ce anomalies, and negative Eu anomalies. Such characteristics of REE compositions are indicative of similar evolved dolomitizing fluid, such as seawater or seawater- derived fluids. By contrast, SD dolomites have a different REE partition pattern with left-leaning characteristics, LREE depletions, and negative Eu anomalies, thus suggesting a different dolomitizing fluid source from the matrix dolomites. In addition, the development of intercrystalline pores associated with D2 dolomite makes it more likely to be a potential reservoir, indicating that the dolomitizing history of carbonate has a strong influence on the quality of potential dolomite reservoirs.

Old Mesoproterozoic−Cambrian successions have been regarded as an important frontier field for global oil and gas exploration in the 21st century. This has been confirmed by a recent natural gas exploration breakthrough in the Sinian and Cambrian strata, central Sichuan Uplift, Sichuan Basin of SW China. However, the accumulation mechanism and enrichment rule of these gases have not been well characterized. This was addressed in this work, with aims to provide important guidance for the further exploration while enriching the general studies of the oil and gas geology in the old Mesoproterozoic–Cambrian strata. Results show that the gas field in the study area is featured by old target layers (Sinian–Lower Cambrian), large burial depth (>4500 m), multiple gas-bearing intervals (the second and fourth members of the Sinian Dengying Formation and the Lower Cambrian Longwangmiao Formation), various gas reservoir types (structural type and structural–lithologic type), large scale (giant), and superimposing and ubiquitous distribution. The giant reserves could be attributed to the extensive intercalation of pervasive high quality source rocks and large-scale karst reservoirs, which enables a three-dimensional hydrocarbon migration and accumulation pattern. The origin of natural gas is oil cracking, and the three critical stages of accumulation include the formation of oil reservoirs in Triassic, the cracking of oil in Cretaceous, and the adjustment and reaccumulations in the Paleogene. The main controlling factor of oil and gas enrichment is the inherited development of large-scale stable paleo-uplift, and the high points in the eastern paleo-uplift are the favorable area for ​natural gas exploration.

Large gas reserves have been found in the Permian platform margin of the Kaijiang-Liangping area of the Sichuan Basin in SW China. They are assumed to be a widely developed reef–shoal reservoir. However, the tight matrix reservoir cannot support high gas production using conventional development technology at deep subsurface. In this contribution, we analyze the fractured reservoirs along the strike-slip fault zones using the compiled data of cores, well logging, and production data, and provide a seismic description. It was shown that the fractures and their dissolution developed along the strike-slip fault zones. The porosity and permeability of the fractured reservoir could increase by more than one and 1–2 orders of magnitude, respectively. The seismic anisotropic energy found in the steerable pyramid process suggests that fractured reservoirs have a strong heterogeneity, with a localized fault damage zone. This fracturing has both positive and negative effects, showing varied reservoir parameters in the fault damage zone. The development pattern should adopt a non-uniform well pattern, in order to target the localized “sweet spot” of the fractures in these deep tight matrix reservoirs.

This study investigates the impact of the Emeishan Large Igneous Province (ELIP) on hydrocarbon formation within the Anyue gas field in the Sichuan Basin. As a major Middle to Late Permian large igneous province, the ELIP hosted intense mantle plume activity that reshaped regional tectonics and thermal structures, indirectly influencing hydrocarbon accumulation. This paper examines three primary factors in hydrocarbon evolution linked to the ELIP: its thermal influence, induced fluid activity, and role in hydrocarbon cracking. Data reveal that the thermal effects of the ELIP extend to the central Sichuan Basin, where an elevated paleogeothermal gradient has driven hydrocarbon evolution in the Anyue gas field. Petrographic characteristics, chronological data, fluid inclusion features, and C–O, S, and Pb isotopic signatures collectively indicate that around 260 Ma, a hydrothermal event occurred in the Sichuan Basin, closely aligned with a natural gas charging event. The combined effects of a heightened geothermal gradient and hydrothermal fluids (with temperatures up to 320 °C) suggest that paleo-oil reservoirs had already cracked into natural gas during the peak ELIP activity.

Azimuthal traveltime analysis provides comparatively stable fracture-orientation estimates but limited information on fracture-related elastic changes, whereas amplitude variation with offset (AVO) inversion is sensitive to residual azimuthal moveout. We propose a sequential offset vector tile (OVT)-domain azimuthal traveltime-constrained AVO inversion workflow for reservoir-scale fracture characterization. Traveltime responses are first used to estimate the locally dominant fracture orientation and reduce azimuth-dependent event misalignment. Prestack AVO inversion is then applied separately to representative fracture-parallel and fracture-perpendicular gathers to obtain two sets of apparent elastic parameters, from which a relative tangential-weakness attribute ($\Delta e$) and Poisson’s ratio ratio ($R_{\nu }$) are derived. Synthetic tests show that the mean fracture-orientation error is no greater than 1.1° for prescribed noise levels of 0–50%, and that varying the maximum incidence angle from 20° to 40° causes no systematic deterioration in the recovered attributes. In the field application, the predicted dominant orientation of N 45° E–N 60° E agrees with the approximately N 50° E fracture trend identified from an independent structure-tensor-based seismic interpretation near ZT3. Compared with the uncorrected results, the corrected $\Delta e$ and $R_{\nu }$ maps exhibit improved continuity and better spatial correspondence with the independently interpreted fracture pattern. These results demonstrate that the proposed workflow effectively integrates the stable directional constraint provided by azimuthal traveltime analysis with the fracture-related elastic information obtained from directional AVO inversion, enabling reservoir-scale characterization of the dominant fracture orientation, relative fracture-related weakness variation, and possible fluid sensitivity. Within the stated assumptions and applicability conditions, the method provides a practical seismic framework for fractured-reservoir characterization and evaluation.