To guide the future deployment of natural gas exploration in the Sichuan Basin, this paper systematically summarized the critical theoretical understandings, technical progress and significant achievements with respect to risk exploration in the basin since the 13th Five-Year Plan began. Based on the exploration practices of PetroChina Southwest Oil&Gasfield Company, the geological conditions for gas accumulation were investigated in four major domains (marine conventional gas, continental tight gas, shale gas, and coal-rock gas), the collaborative innovations in geophysical and engineering technologies were analyzed, and the controls of tectono-sedimentary evolution on large-scale reservoir-controlling geological units were clarified. The following results are obtained. (i) In terms of marine conventional gas, the “four-paleo” accumulation theory (paleo-rift trough, paleo-platform, paleo-oil cracking gas, and paleo-uplift) and the new insights on trough-platform differentiation were deepened, and an innovative model of “three-dimensional hydrocarbon accumulation in traps controlled by faults and lithologies” was established for slope zones, supporting the identification of five new areas such as Penglai, southwestern Sichuan Basin, and northwestern Sichuan Basin, each with reserves exceeding 1 000×108 m3, contributing the addition of proven gas in place (GIP) over 1.27×1012 m3. (ii) In terms of continental tight gas, a strategic shift from lithologic gas reservoirs in uplift areas to inner-source tight gas reservoirs in depression areas was achieved in accordance with the theory of whole petroleum system, with newly added GIP of 1 110×108 m3 in the Triassic Xujiahe Formation, northwestern Sichuan Basin, suggesting a resource potential up to 3.04×1012 m3. (iii) In terms of shale gas, the enrichment model controlled by the trough-uplift spatiotemporal coupling for the Cambrian Qiongzhusi Formation and the “four-high” (high TOC, high brittle mineral, high porosity, and high gas content) quality shale evaluation system for the Permian Wujiaping Formation were established, and two 1.00×1012 m3-scale strata were defined for exploration. (iv) In terms of coal-rock gas, a new “dual” occurrence mechanism for deep Permian Longtan Formation featured with high pressure, high gas saturation and high free gas content was revealed, leading to a novel strategic discovery with the favorable area predicted to be 1.04×104 km2. It is concluded that the continuous growth of natural gas reserves and production in the Sichuan Basin will be primarily secured by enhancing the basic research on large-scale reservoir-controlling geological units, developing high-resolution seismic imaging and subtle trap identification technologies, and improving the adaptability of ultra-deep reservoir stimulation and deep shale gas reservoir fracturing processes.
In order to clarify the natural gas enrichment patterns and exploration targets in the Sichuan Basin, a systematic study was conducted under the framework of tectonics controlling basins, basins controlling sedimentation, and tectonics and sedimentation controlling reservoir-forming assemblages. The study comprehensively analyzed the geological conditions for the formation of this super basin, summarized the natural gas enrichment patterns controlled by tectonic sequence, and proposed key targets for future exploration. The following results are obtained. (i) Controlled by the evolution of the Tethyan tectonic domain, the Sichuan Basin underwent three major evolutionary stages: the Nanhuaian intracontinental rift basin, the Ediacaran-Middle Triassic cratonic basin, and the Late Triassic-Jurassic foreland basin. The basin-wide gas-bearing potential in planar distribution and the vertical superposition of multiple petroleum systems are key factors controlling the formation of the gas-rich super basin. (ii) Intense intracratonic tectonic differentiation governs the spatial distribution of paleo-rifts, paleo-platform margins, and paleo-uplifts, thereby shaping the distribution pattern of large-scale gas reservoir-forming elements. Deep to ultra-deep carbonate reservoirs are characterized by multi-stage hydrocarbon accumulation, near-source hydrocarbon enrichment, and tectonic differentiation controlling zone. (iii) The migration of depositional and subsidence centers in the foreland basin forms a “sandwich-type” proximal reservoir-forming assemblage. Shallow to medium tight gas reservoirs exhibit the features of fault-sandstone coupling, near-source migration, and multi-layer accumulation. The Upper Triassic Xujiahe Formation in the foreland depression-slope zone demonstrates the characteristics of full-sequence hydrocarbon accumulation. Key targets for gas exploration are proposed as follows: from the practical perspective, deep to ultra-deep carbonate rocks, tight gas in the Xujiahe Formation-Middle Jurassic Shaximiao Formation in the foreland depression-slope zone, and shale gas in shelf facies are critical to supporting the Sichuan Basin’s gas production breakthrough of 100 billion cubic meters by 2030; from the potential perspective, the ultra-deep Neoproterozoic Qingbaikou-Nanhua rift systems in the central basin, deep layers or nappe footwall in the foreland thrust belts along the basin margin, and the Lower Paleozoic shale gas in central Guizhou-western Hubei areas outside the basin should be evaluated as soon as possible.
As the successive discovery of large Sinian gas fields such as Weiyuan, Anyue and Penglai in the Sichuan Basin, deep to ultra-deep strata have demonstrated attractive prospects of petroleum exploration. The primary task of deep to ultra-deep petroleum exploration in this basin is to determine the distribution and characteristics of the prototype basin, thereby revealing its early stage tectonic background. Based on the latest data such as gravity, magnetic, electrical methods, seismic surveys, drilling, paleomagnetism, magmatic rock ages, and geochemistry, the basement structure and tectonic position of the Sichun basin were clarified. This study reveals the peripheral tectonic processes and deep geological background, systematically analyzing the tectonic setting of the Upper Yangtze Block during different periods of the Neoproterozoic. The study suggests that the Yangtze Block may have formed through the amalgamation of the Shennong terrane in the northwest and an oceanic plateau in the southeast. The Yangtze Block and the Cathaysia Block collided between 820 and 810 Ma to form the South China Block. The Sichuan Basin exhibits a dual-basement configuration, comprising the Late Archean to Paleoproterozoic crystalline basement and the Mesoproterozoic folded basement. During the Neoproterozoic to Early Paleozoic, the Yangtze Block was located on the northwestern margin of the Rodinia supercontinent, close to the Australian or Indian continent. The Yangtze Block experienced three tectonic-magmatic events in the Neoproterozoic, reflecting the entire process of subduction and back-arc extension of the Proto-Tethys Ocean. After approximately 810 Ma, the Upper Yangtze Block entered an extensional tectonic regime, developing a series of “wide rift” basins in a back-arc setting. The Yangtze Block underwent a complete convergence-extension cycle during the Neoproterozoic, with the extensional rift basins being the primary target for deep to ultra-deep exploration studies.
As one of the most complex gas reservoir types in the world, the subtle lithologic gas reservoirs in the Sichuan Basin possess enormous resources and widespread distribution, making them a critical option for current and future natural gas reserve expansion and production enhancement. However, these reservoirs are characterized by strong heterogeneity, indistinct gas-water differentiation, and weak acoustic impedance differences between the gas reservoir and surrounding rocks, resulting in weak seismic response signals that severely constrain their effective identification and detailed characterization. In response to these challenges, this paper reviews the advances and difficulties in several geophysical technologies such as prestack amplitude-preserving processing and AVO attribute extraction, multiple suppression, high-resolution imaging of converted waves, prestack waveform classification, facies-controlled reservoir prediction, shear-wave information characterization, multi-parameter joint inversion, and gas-bearing prediction, and proposes corresponding suggestions. It is indicated that remarkable advances have been made in exploration technologies for subtle lithologic gas reservoirs in the Sichuan Basin, especially with respect to prestack amplitude-preserving processing, deep wave suppression, shear-wave imaging, and multi-parameter inversion. However, in complex structural zones, deep reservoirs, and cases with weak AVO signals, existing seismic exploration techniques cannot accurately identify thin reservoir layers and complex fault structures, and may yield multi-solutions of inversion. Efficient exploration and development of subtle lithologic gas reservoirs in the Sichuan Basin will require: (1) expanded coverage of 3D seismic data to enhance the imaging quality in key areas; (2) high-accuracy seismic acquisition technology to improve the data frequency and resolution; (3) more intelligent and automatic seismic survey systems to enhance the operational efficiency and data interpretation accuracy; and (4) collaborative innovation in geophysics, geology and engineering technology to establish a system of comprehensive seismic exploration technologies specific to the Sichuan Basin.
In order to clarify whether the Lower Silurian Longmaxi Formation source rocks have contributed to the Upper Permian Changxing Formation gas reservoirs in the central Sichuan Basin, gas chromatography-mass spectrometry (GC-MS) tests were conducted on source rocks from the Longmaxi Formation, Middle Permian Maokou Formation, and Upper Permian Longtan Formation, as well as solid bitumen from the Changxing Formation in the Jianshuigou section of the Huayingshan area. The source of solid bitumen in the Changxing Formation was identified to verify the contribution of Longmaxi Formation source rocks to Changxing Formation gas reservoirs. The following results are obtained. (i) The Longmaxi Formation source rocks are deposited in the lowest salinity water body, showing relatively high organic matter contribution from red algae; the Maokou Formation source rocks are deposited in the highest salinity water body, with green algae being an important hydrocarbon-generating parent material; whereas the Longtan Formation source rocks are deposited in water body with moderate salinity, with organic matter mainly supplied from red algae, green algae, and higher plants. (ii) The Changxing Formation solid bitumen in the Jianshuigou section of the Huayingshan area is of thermochemical alteration origin, primarily derived from the Longmaxi Formation source rocks. (iii) Deep-seated faults serve as favorable vertical migration pathways for deep hydrocarbons, enabling the transport of hydrocarbons generated by the Longmaxi Formation source rocks to the Changxing Formation for accumulation. It is concluded that the deep-seated faults can transport the hydrocarbons generated by the Longmaxi Formation source rocks to the Changxing Formation for accumulation. Eastern margin of the Mianyang-Guang’an shallow-water shelf, where deep-seated faults extending into the Changxing Formation are developed and the Longmaxi Formation source rocks are of high quality, is conducive to gas accumulation. Therefore, the exploration potential of Changxing Formation gas reservoirs deserves attention.
To understand the enrichment patterns and exploration potential of deep tight sandstone gas in the Upper Triassic Xujiahe Formation in the Sichuan Basin, systematic researches were conducted based on latest drilling and seismic data acquired in the exploration area of China Petrochemical Corporation (Sinopec) in the basin. An isochronous stratigraphic framework was established and the tectono-paleogeography was reconstructed. Essential hydrocarbon accumulation elements such as source rock and reservoir, as well as their spatiotemporal matching relationships, were analyzed. Then, the dynamic evolution process of tight sandstone gas accumulation in this formation was investigated. Finally, the main factors controlling the differential gas enrichment were identified, and the favorable exploration zones were evaluated. The following results are obtained. (i) The Xujiahe Formation in the study area experienced three tectonic movements (Indosinian, Yanshanian, and Himalayan), resulting in three sets of source rocks (Xu 1 Member, Xu 3 Member, and Xu 5 Member) and three sets of reservoirs (Xu 2 Member, Xu 4 Member, and Xu 6 Member), forming a favorable “three-source, three-reservoir” configuration. (ii) The gas enrichment is constrained by three “controls”: the control of structures on zones in the early stage, that is, paleo-structures laid the foundation of gas enrichment zones; the control of differential densification on reservoirs in the middle stage, that is, the differential densification process created relatively good reservoirs; and the control of reworking-induced fractures on productivity, that is, the fracture network formed by tectonism governed the distribution of productive “sweet spots” in the late stage. (iii) Key support technologies are developed, including log-based evaluation of deep tight clastic rocks, quantitative matrix reservoir prediction and fracture-developed zone depiction and inversion based on classified lithofacies, and comprehensive fracturability index evaluation, which have supported the discovery and production of large gas fields such as Hexingchang and Tongnanba. The Xu 2 Member in the Fenggu area, western Sichuan Basin, and the Xu 2 and Xu 4 Members in the Bazhong-Tongjiang area, northeastern Sichuan Basin, are identified as core targets for subsequent tight sandstone gas exploration. Moreover, it is proposed that future research priorities will focus on geologic theory, logging prediction, seismic prediction, and reservoir stimulation. Once breakthroughs are achieved, they are expected to facilitate subsequent exploration of tight sandstone gas in the Xujiahe Formation of the Sichuan Basin.
To identify the tectono-sedimentary evolution pattern of the Sichuan Basin in the marine craton stage and clarify the controls of paleo-rifts and paleo-uplifts on the development of large-scale reservoir facies zones, a systematic study of the tectono-sedimentary evolution was conducted based on 2D and 3D seismic data, field outcrops at the basin margin, and drilling and logging data of the basin. The following results are obtained. (i) The marine strata in the Sichuan Basin mainly experienced four periods of tectonic cycles: Xingkai, Caledonian, Hercynian, and Indosinian, forming a tectono-sedimentary pattern characterized by alternating uplifts and depressions. (ii) Under the extensional tectonic setting, during the Tongwan period, the Deyang-Anyue and Chengkou-Shizhu rifts were formed in the basin, which controlled the distribution of contiguous mound-shoal complexes along rift trough margins; during the Hercynian period, the Kaijiang-Liangping trough, the Chengkou-Western Hubei trough, and the Pengxi-Wusheng shallow water shelf were formed, controlling the widespread development of the Permian and Triassic reef-shoal deposits in marginal zones. (iii) Under the compressional tectonic setting, the central Sichuan paleo-uplift was shaped during the Caledonian period, dominating the large-scale development of multi-stage Cambrian and Ordovician shoal bodies around the paleo-uplift; during the Indosinian period, the Luzhou-Kaijiang paleo-uplift was formed, controlling the distribution of shoal-facies sedimentation in the Lower Triassic Jialingjiang Formation and the Middle Triassic Leikoupo Formation. It is concluded that the slope-break zones along the margins of paleo-rifts and paleo-uplifts control the large-scale distribution of high-energy mound-shoal complexes, laying the foundation for the development of porous reservoirs. These highly potential zones remain the key targets for future gas exploration in marine cratonic strata of the Sichuan Basin.
The Daqing Oilfield exploration area (Daqing exploration area for short) in the Sichuan Basin vertically develops over 16 marine and continental target strata, with less than 7% gas reserves proved, suggesting enormous exploration potential. To fully tap into the potential of oil and gas resources and improve the quality and efficiency of exploration and development, Daqing Oilfield has carried out systematic research targeting the Hechuan-Tongnan and Yilong-Pingchang blocks. By continuously deepening the understanding of regional geology, focusing on key technical challenges, and promoting the transformation and upgrading of exploration and development models, the oilfield has realized a leap from “strategic three-dimensional exploration” to “efficiency concentrated exploration” and a shift from “development pilot tests” to “large-scale profitable development”. Systematic investigation has been conducted centering on three key domains: conventional gas in the Middle Permian Maokou Formation, tight gas in the Upper Triassic Xujiahe Formation, and shale oil in the Middle Jurassic Lianggaoshan Formation. The following results are obtained. (i) In terms of conventional gas in marine carbonates, a ternary reservoir-controlling model of “shoal facies + karstification + dolomitization” is established for the Maokou Formation, with proved gas reserves of 2 132×108 m3 submitted cumulatively, laying a resource base for a trillion-cubic-meter gas province. (ii) In terms of tight gas, a vertical multi-layer stereoscopic hydrocarbon accumulation model is constructed for the Xujiahe Formation, with three major enrichment zones showing prospective resource potential of 1.6×1012 m3 of gas, expected to become another new reserve growth target on a scale of 1 000×108 m3 following the Maokou Formation. (iii) In terms of shale oil, further research on source-reservoir coupling is conducted for the Lianggaoshan Formation, with possible shale oil reserves of 9 032×104 t submitted for the first time, breaking new ground in Jurassic shale oil exploration. Shale oil in this formation is expected to achieve 100-million-ton-scale growth in reserves, making it a practical option for large-scale oil exploration in the Sichuan Basin. It is concluded that the exploration in the three key domains has achieved remarkable results, not only providing a solid resource guarantee for reserve growth and production increase in this exploration area, but also offering a reference for hydrocarbon exploration and development in domestic basins with similar geological conditions.
In order to clarify the lithofacies types, source rock conditions, and reservoir properties, identify the dominant lithofacies associations of the Lower Jurassic Lianggaoshan Formation in the Sichuan Basin, a comprehensive evaluation was conducted on lithofacies, lithofacies associations and their relationships with hydrocarbon generation and accumulation, through analyses of petrology, geochemistry and reservoir physical properties using field outcrop sections and drilling core data. The following results are obtained. (i) There develops six lithofacies types in the Lianggaoshan Formation of this basin: sandstone (Type A), siltstone (Type B), massive shale (Type C), laminated shale (Type D), (thin) interbedded sandstone-mudstone (Type E), and mudstone (Type F). (ii) On the basis of lithofacies classification above, five types of lithofacies associations are identified as: sandstone + massive shale (TypeⅠ), sandstone＋mudstone (TypeⅡ), sandstone＋siltstone (TypeⅢ), (thin) interbedded sandstone-mudstone + laminated shale (TypeⅣ), and laminated shale＋massive shale (TypeⅤ). (iii) The Lianggaoshan Formation shales exhibit the average total organic carbon (TOC) of 1.55% and the average hydrocarbon generation potential (S1+S2) of 2.21 mg/g. Specifically, Types C and D reflect good source rock conditions, while Type E shows relatively poor ones. (iv) Lithofacies types vary significantly in reservoir properties, with the average porosities of 5.30%, 1.44%, 3.42%, 3.24%, and 2.22% for Types A, B, C, D, and E, respectively. It is evident that Types A exhibits notably higher porosity than the other lithofacies, followed by Types C and D, then Type E, while Type B shows the lowest porosity. (v) Comprehensive analysis on lithofacies associations demonstrates that TypeⅠ has the best source rock and reservoir conditions, indicating the optimal association. Meanwhile, TypesⅣ and Ⅴ are both favorable ones. It is concluded that the Lianggaoshan Formation in the Sichuan Basin has a promising potential, and the clarification of dominant lithofacies associations provides a theoretical support for shale oil and gas exploration and development.
The Deyang-Anyue trough in the Sichuan Basin plays a vital role in controlling the formation and distribution of gas reservoirs in the Sinian Dengying Formation. However, the contentious stratigraphic division and limited studies on sedimentary characteristics and evolution process in this area impede the exploration progress of the Dengying Formation gas reservoirs. To clarify the stratigraphic characteristics and sedimentary pattern variations, the Dengying Formation in the study area was redefined using new well logging data (cuttings, cores, and conventional logs) and 3D seismic data to determine its distribution, and the sedimentary characteristics and evolution process were thoroughly discussed. The following results are obtained. (i) The Dengying Formation within the trough is generally complete in stratigraphic sequence, with only the absence of the third and fourth members of the Formation (Deng 3 and Deng 4 Members for short) in the southern part. The trough had already formed by the end of the sedimentary stage of Deng 2 Member. Moderate filling during the Deng 3 Member stage lead to a slight reduction in the difference between terrain elevations inside and outside the trough. The paleotopography in the Deng 4 Member, largely inherited from the late stage of Deng 2 Member, accentuates the geomorphological contrast inside and outside the trough. (ii) The sedimentary facies such as slope-shelf, platform margin, semi-restricted platform, and mixed platform are identified in the Dengying Formation within the trough and its periphery, with their types and distribution controlled by the trough morphology and scale. (iii) The sedimentary evolution progresses in stages. In the early stage of Dengying Formation, differential subsidence and dissolution thinned original facies zones in the Deng 1 and Deng 2 Members, recording the initiation of the trough. In the middle stage, the geomorphological contrast triggered sedimentary differentiation, resulting in the distribution of low-energy slope-shelf deposition within the trough and high-energy platform deposition outside the trough. In the late stage, tectonic uplift caused stratigraphic exposure and erosion, making the Deng 3 and Deng 4 Members absent locally. (iv) The analysis of stratigraphic division and reservoir-development characteristics shows that the areas favorable for mound-shoal complex development are identified, including the PT1-PT103-PS3, MX8, and GS137 wellblocks in the Deng 1 and Deng 2 Members and the DT1, PT103-PT101-GS102 wellblocks in the Deng 4 Member. This study clarifies the stratigraphic characteristics, sedimentary features, and evolution of Dengying Formation in the middle section and eastern margin of the Deyang-Anyue trough, providing a significant geological basis for efficient gas exploration.
To understand the densification genesis and differential evolution characteristics of tight sandstone reservoirs in the first member of the Middle Jurassic Shaximiao Formation (Sha 1 Member), southwestern Sichuan Basin, a systematic study was conducted based on core, thin-section, and scanning electron microscopy (SEM) observations, as well as petrophysical test data. The study adopted an integrated approach combining petrological analysis, quantitative characterization of diagenesis, and inversion of porosity evolution history to identify the main controlling factors and differential evolution mechanisms of reservoir densification in this area. The following results are obtained. (i) The tight sandstone reservoirs of the Sha 1 Member are governed jointly by provenance, sedimentation, and diagenesis, with significant provenance zoning. Sandstones from the Longmenshan provenance generally contain lithic fragments exceeding 30%, inducing early calcite cementation, leading to rapid loss of primary pores. In contrast, sandstones from the Kangdian provenance are characterized by high feldspar content, which enhances the compaction resistance of rigid grains and provides materials for later dissolution. (ii) Sedimentary microfacies control initial pore structure through rock fabric. High-energy subaqueous distributary channels and mouth bars, with optimal physical properties, serve as preferential pathways for later acidic fluid migration. (iii) Diagenesis directly control reservoir densification. During the early diagenetic stage, compaction dominated, causing 7%-12% loss of primary pores. Acidic fluid activity intensified during the middle diagenetic stage, with feldspar dissolution contributing 2%-6% porosity increment. (iv) Based on diagenetic intensity classification (incl. compaction, cementation, and dissolution), four reservoir types are identified: CCAB, CACC, ABCB, and BCBA. (v) Inversion of porosity evolution history reveals distinct densification processes. The CCAB type is benefited from early chlorite rim cememtation for pore protection and late dissolution for pore increase, achieving porosity of 12.26%. The CACC type, due to the early basal calcite cementation blocking pores and minimal later dissolution, shows porosity of only 1.68%. The ABCB type is dominated by continuous strong compaction, resulting in porosity of 6.65%. The BCBA type exhibits significant porosity enhancement due to near-fault intensive dissolution, partially offset by kaolinite filling, yielding porosity of 10.31%. It is concluded that the differential densification of the Sha 1 Member reservoirs in the study area results from the spatiotemporal coupling of provenance influencing diagenetic pathways, sedimentation controlling initial frameworks, and diagenesis directly causing densification. Specifically, areas near faults influenced by the Kangdian provenance are favorable zones for development of CCAB-type high-quality reservoirs.
To elucidate the differential enrichment patterns and resource potential of coalbed methane (CBM) and coal-rock gas (CRG) in the Upper Permian of the southern Sichuan Basin, a systematic study was conducted on the differential accumulation characteristics and exploration potential of shallow CBM and deep CRG in the study area, considering the regional exploration and development practices, and combining the methods of sedimentary facies analysis, reservoir characterization, gas-bearing test, and resource evaluation. The following results are obtained. (i) The Late Permian paleogeographic framework and transgression process controlled the spatiotemporal distribution of coal seams. The Xuanwei Formation coalbeds, characterized by shallow burial and relatively concentrated distribution, developed along the basin margin, whereas the Longtan Formation coal rocks, featuring deep burial, multiple layers, and thin single layers, developed in the basin interior, constituting the material foundation for differential accumulation. (ii) The shallow mountainous CBM in the basin margin is remained gas, which is enriched essentially attributable to preservation conditions controlled by the coupling of four factors, i.e. tectono-thermal evolution, structural features, sedimentary environment, and hydrogeology. The gas ultimately occurs in local “safety islands” formed by synclinal structures and hydrodynamic trapping, with resources reaching 2 861×108 m3. (iii) The CRG in the basin interior is considered to be the gas accumulated continuously or in situ, essentially following a mechanism of primary accumulation, characterized by “box-style sealing, source-reservoir integration, and coexistence of adsorbed and free gas”. Free gas accounts for an average of 16.56%, formation pressure coefficients range from 1.2 to 2.0, and resource scale reaches level of 1×1012 m3. (iv) The shallow CBM has been commercially developed in the Junlian block, and its potential for future development will be concentrated in unproduced reserves and peripheral replacing areas. The deep CRG, due to its enormous resource scale, high gas content, and advantage in overpressure, has become the most important strategic replacement frontier in the Sichuan Basin. It is concluded that two essentially distinct accumulation models, i.e. CBM as remained gas accumulation in shallow strata and CRG as continuous accumulation in deep strata, are identified in the Upper Permian of the southern Sichuan Basin. “Structure-hydrogeology coupled safety islands” and “sweet spots within box-style sealing systems” represent the favorable exploration directions for these two models, respectively. This study provides important theoretical evidences for exploration and commercial development of CBM and CRG in the study area.
To further enhance deep to ultra-deep seismic exploration capabilities and address the challenges of strong heterogeneity and low seismic prediction accuracy in carbonate reservoirs, a deep and thorough investigation was made on key technologies, including fine identification of subtle structural traps, micro-paleogeomorphology analysis based on intelligent fine layer correlation, and high-resolution quantitative characterization of heterogeneous reservoirs. The supporting technologies have been developed and widely applied to the Sinian Dengying Formation and Permian Maokou Formation in Sichuan Basin. Results show that (i) prestack depth migration based on fine velocity modeling can effectively solve the problem of inaccurate energy positioning caused by overlying gypsum-salt layers; (ii) micro-paleogeomorphology analysis based on the optimal basis wavelet time-frequency decomposition improves the identifiability of internal layer interfaces by utilizing the abundant frequency-domain information of seismic data; and (iii) high-resolution quantitative characterization of heterogeneous reservoirs driven by waveforms effectively addresses the issue of low accuracy in vertical and lateral quantitative prediction of deep reservoirs. It is conclude that the proposed technologies improve the prediction accuracy of subtle structures, micro-paleo geomorphology, and heterogeneous reservoirs, demonstrating good stability and reliability. Also, these technologies have supported the establishment of a trillion-cubic-meter-scale gas area in the Penglai area of the northern slope in central Sichuan Basin and ensured that 100% of the wells drilled in the platform-margin zone of the Permian Maokou Formation in central Sichuan Basin encountered high-quality reservoirs. The research findings provide reference for the exploration and development of similar complex carbonate reservoirs in other basins in China.
The Upper Sinian Dengying Formation in the Sichuan Basin is characterized by complex lithology and difficulty in fine depiction for sedimentary microfacies, constraining the accurate prediction of high-quality reservoirs. To improve the accuracy of sedimentary microfacies classification, the sedimentary characteristics of dolomites in the fourth member of Dengying Formation (Deng 4 Member) in the northern Sichuan Basin were systematically investigated, based on a comprehensive study integrating core observations, thin-section analysis, conventional logging and high-resolution image logging data from Well Wang 1. The following results are obtained. (i) The Deng 4 Member in Well Wang 1 develops both platform margin and restricted platform facies. The former comprise three subfacies: platform-margin mound, platform-margin shoal, and platform-margin mound-shoal complex, corresponding to six microfacies types. The latter mainly consist of tidal flat subfacies, including supratidal flat and intertidal dolomitic flat microfacies. (ii) Deep resistivity, density, and natural gamma-ray logs demonstrate good performance in identifying platform-margin shoal and tidal flat subfacies. Specifically, deep resistivity log is sensitive to platform-margin shoal, while density and natural gamma-ray logs effectively distinguish microfacies such as supratidal flat, intertidal dolomitic flat, and sandy shoal. However, different microfacies within platform-margin mounds and mound-shoal complexes exhibit significant overlap in conventional log intersection space, resulting in limited resolution. (iii) Dissolution pores and vugs are developed in mound cores and sandy shoals in platform-margin facies, appearing as dark spots, whereas mound bases and inter-mound areas display reticular patterns, and mound flats are dominated by bright spots. In restricted platform, intertidal dolomitic flats show bright massive features, with pinhole-like dissolution pores observed locally, while supratidal flats are characterized mainly by reticular patterns. (iv) Reservoir quality is jointly controlled by lithology and sedimentary microfacies. Algal clotted, algal stromatolitic, and arenaceous dolomites formed under strong hydrodynamic conditions retain relatively abundant primary pores, which are enhanced by early-stage dissolution to create favorable reservoir space. In contrast, micritic to microcrystalline dolomites formed under weak hydrodynamic conditions are relatively tight and unfavorable for the development of high-quality reservoirs. These findings enhance the understanding of sedimentary facies of the Sinian Dengying Formation carbonate rocks, and provide theoretical support and technical guidance for natural gas exploration and development of the Dengying Formation in the Sichuan Basin.
Wellbore instability is induced by tensile fracture propagation during drilling in deep shale formations of the Sichuan Basin. Taking the deep shales of the Lower Silurian Longmaxi Formation in the Penglai gas field of this basin as an example, by integrating mineral composition analysis, mechanical property experiments, and theoretical modeling, the propagation mechanism of tensile fractures was systematically revealed, and a corresponding formation fracture pressure prediction model was established. Results indicate that (i) under large burial depth and strong in-situ stress conditions, the Longmaxi Formation shales exhibit significant heterogeneity in mineral composition and microstructure, with obvious presence of bedding structures. The fracture propagation paths are jointly controlled by bedding structures and mineral distribution; (ii) shale failure modes are categorized into three types: propagation along bedding planes, composite propagation along bedding planes and loading directions, and penetrating propagation along loading direction. The tensile fracture propagation process sequentially undergoes three stages: crack initiation, propagation, and coalescence, with low-angle bedding planes being more prone to induce crack initiation and propagation; (ii) the classical fracture pressure prediction model was modified by introducing a structural correction coefficient m and considering the heterogeneity of mineral distribution and the anisotropy of tensile strength. Field validation demonstrates that the revised model can more realistically reflect the properties of shale reservoirs in the study area, providing a reliable basis for determining the safety drilling fluid density window adaptable to deep shales.
