As critical infrastructure for seasonal peak-shaving and emergency gas reserves, dynamic analysis of underground gas storage (UGS) is pivotal to ensuring safe and efficient operations. This study systematically investigates the formation mechanisms, impacts, and multidimensional countermeasures for core dynamic issues during UGS operations, including pressure, temperature, compositional variations, and fluid flow dynamics. Validation through global case studies demonstrates that implementing a comprehensive management framework featuring “three-dimensional monitoring, quantitative analysis, and intelligent regulation” significantly enhances operational safety and economic efficiency. Results show an average 12.7

The successful application of horizontal salt cavities is crucial for building gas storage in thin salt layers, but the technology is nascent. This study focuses on the stability of horizontal salt cavity structure. By establishing numerical models based on Russia's experiment, it analyzes the influence of cavity length, cross-sectional morphology and maximum diameter on stability. Results show that: 1) A longer horizontal cavity length leads to greater cavity roof deformation, a higher volume shrinkage rate, and weaker cavern stability; 2) Circular cross-sections result in the least cavity roof deformation and volume shrinkage rate; conical ones maximize the plastic zone and volume shrinkage rate, while arched ones minimize the plastic zone volume; 3) An increase in diameter raises cavity roof deformation, plastic zone volume, and volume shrinkage rate; 4) Diameter change affects stability more significantly than length and cross-sectional structure. It is recommended to set the horizontal salt cavern length at 425 m, choose a circular cross-section with a maximum diameter of 30 m. Given that actual cross-sections are mostly arched, the maximum cross-sectional diameter should be reasonably controlled. This study can provide guidance for designing salt cavern morphology in horizontal gas storage construction within thin salt layers.

Underground gas storage (UGS) is one of efficient way for natural gas peak shaving regulation, with which sealing integrity during the gas injection and withdrawal is the key issue for the UGS operation. In this study, a one-way geomechanical modeling as well as rock mechanical test was performed in the Nanpu-1 depleted oil reservoir which located in the Eastern China Nanpu sag. The modeling is coupled with a dynamic model to investigate the geomechanical behavior of faulted reservoirs during gas injection and production as well as estimate the reservoir and caprock integrity and evaluate the risk of fault reactivation. The results show that horizontal stresses and formation pressure in the sandstone reservoirs are distinctly affected by the gas storage while change slightly in the caprocks. The caprocks have a good mechanical integrity before and during the UGS construction, with the shear safety factor ranging from 0.35 to 0.62. The slip index indicates that faults in the UGS is stable with the FSI value less than 1.0 even at the maximum pressure. Furthermore, the critical formation pressure for the fault activation is estimated as 34.5 MPa. The study implies that the Nanpu-1 UGS can be safely operated at least 20 years without any risk from the caprocks or the cross-cutting faults. The tight caprocks are insensitive to the pressure changes in contrast with the reservoirs due to the weak hydraulic communication. In addition, evaluation of fault reactivation should overall consider stress state along fault planes in the whole UGS.

In the Jidong region of the JS Basin, deep shale gas horizontal wells at depths over 3,500 meters have experienced casing deformation issues during staged fracturing operations. This problem has significantly constrained the development efficiency of deep shale gas in this area. A multi-factor analysis was conducted on typical deep shale gas horizontal wells in the Jidong block, further clarifying the main characteristics and causes of casing deformation. Physical simulation analysis of casing deformation during shale gas well fracturing revealed the mechanism behind the casing deformation, providing a theoretical basis for prediction and prevention. It was found that casing deformation in deep horizontal wells in the Jidong block is primarily influenced by geological and engineering factors. During fracturing, large volumes of fracturing fluid are injected into the formation, and after connecting with natural fractures, the formation exerts shear stress on the wellbore, leading to casing damage. The results show that in the presence of natural fractures, varying stress conditions can alter the direction of hydraulic fracture propagation. Under strike-slip fault stress conditions, hydraulic fractures are prone to deflection, causing shear deformation. The stress state and the inclination of natural fractures are the primary factors influencing the slip and movement of the fracture surfaces. Under strike-slip fault stress conditions, natural fractures are more likely to experience slip and shear, leading to casing deformation. The closer the natural fractures are to the Coulomb failure surface, the more likely they are to slip and displace, causing casing deformation. Further analysis of field wells confirmed the contributing factors to casing deformation, providing technical guidance and experience for the prediction and prevention of casing deformation.

Fault sealing evaluation is an important part of the preliminary evaluation of gas storage reconstruction. This article takes the 1-29 fault block of the Nanpu No. 1 structural belt in the Bohai Bay Basin of China as an example, with the goal of constructing a reservoir-type gas storage facility in this fault block and conducts research on the evaluation of the fault sealing of this fault block. A method for evaluating the vertical and lateral sealing properties of faults has been established based on a large amount of well-logging data interpretation, well formation comparison, numerical simulation, and downhole tracer methods. Based on the data from the work area, qualitative evaluation indicators such as fault occurrence, fault properties, combination characteristics, and lithological configuration combinations of the upper and lower walls were selected for fault sealing evaluation. The study area developed two types of sealing: docking sealing and fault rock sealing. The mass fraction (SGR) of fault mudstone in the work area is generally high, reaching up to 78%. The normal pressure of the eight fault sections in the research area ranges from 14.98 MPa to 15.45 MPa, and the normal pressure of the fault plane is greater than 8 MPa. Combined with the SGR value of the fault mud ratio, which is generally greater than 50%, the corresponding sand-to-ground ratio is less than 50%, and the vertical sealing of the fault belongs to the moderate to good category. Based on the comprehensive evaluation above, it is believed that the fault sealing in the research area is good and suitable for the reconstruction of gas storage facilities.

The mechanical stability of faults is crucial for the safe operation of underground gas storage (UGS). The complex fault systems, strong heterogeneity and anisotropy of geological formations, associating with uncertainty of in-situ stress state after long-term exploitation of oil or gas reservoirs and multiple cycles of injection and production, making it particularly challenging to ensure the safe and efficient operation of the UGS in depleted gas reservoirs. This study investigates the Shuang 6 UGS in the Liaohe basin, NE China, employing a hydro-mechanical coupling approach through both simplified simulation modeling and field case analysis. Systematic parametric studies are carried out to illustrate the effect of key factors on fault slippage. Based on the results of fluid migration and geomechanical responses, an advanced critical pressure perturbation method is proposed to evaluate the risk of fault failure. The findings indicate the following: (1) The fault stress profile exhibites greater complexity than pore pressure due to geomechanical interactions between formations with contrasting properties on hanging wall and footwall; (2) The Delta P in the advanced critical pressure perturbation method provides quantifiable criteria for slip risk evaluation; (3) Low injection rates, small difference in Young's modulus between laminated formations, a high permeable fault zone, and damage zone, as well as simultaneous injection or withdrawal on both sides of the fault, may reduce the risk of fault failure; (4) Specific risk-prone areas are identified in the Xing II/III formation and the right side of Faults 2/3 in the SX block of the Shuang 6 UGS. These insights offer practical guidance for UGS design and operational safety management.

The Cambrian pre-salt dolomite sequence in the Tarim Basin is a target zone of great strategic significance for hydrocarbon exploration in the basin. Using the results of the interpretation of 3D seismic data from Lunnan and 2D seismic data covering the whole basin, and based on a synthesis of outcrop data, drilling data, well logs, core data, and thin-section data, and the findings from previous studies, this paper studies the characteristics of the facies of the Middle–Lower Cambrian in the platform area in the Tarim Basin, the formation and evolution of platform margins, and the sedimentary characteristics, lithofacies, and paleogeographic characteristics of the Middle–Lower Cambrian series. Based on the types of lithofacies and the seismic facies analysis, the sedimentary facies of the Middle–Lower Cambrian strata can be classified into the five types. From bottom to top, the Middle–Lower Cambrian have experienced several development stages, including the deposition of continental shelf sediments of the Yuertusi Formation, gently sloping non-rimmed platform margin sediments of the Xiaoerbulake Formation, weakly rimmed platform margin sediments of the Wusongger and Shayilike formations, and strongly rimmed platform margin sediments of the Awatage Formation. In each stage, the platform margin shifted further east relative to its location in the previous stage. Based on these results and previous studies, the lithofacies and paleogeography maps of the Middle–Lower Cambrian in the Tarim Basin are modified, and the implications for hydrocarbon exploration in this area are discussed.

Depleted gas reservoirs are important natural gas storage media, thus research on the mechanical properties and damage evolution of reservoir rocks under alternating load conditions has significant practical implications for seal integrity studies. This paper conducted multi-level cyclic loading triaxial compression experiments on medium-porosity medium-permeability sandstone under different confining pressures and used acoustic emission (AE) instruments to detect the AE characteristics during the experiment, analyzing the mechanical characteristics, AE, and damage evolution characteristics. The experimental results show that after cyclic loading, the peak strength of sandstone increased by 14–17%. With the increase in the upper limit stress of cyclic loading, the elastic modulus showed a trend of first increasing and then gradually decreasing. The damage variable of rock samples rose with a rise in the upper limit stress of cyclic loading and confining pressure, and the rock damage was mostly localized at the peak stress. The AE b-value increased generally as confining pressure increased, showing that fractures occurred quicker and more unevenly at lower confining pressures. The distribution of RA-AF values shows that a sudden increase in stress causes the initiation and expansion of cracks in medium-permeability sandstone, and that tensile and shear cracks form continuously during the cyclic loading process, with shear cracks developing more pronounced. This research can provide some theoretical guidance for the long-term stable operation and pressure enhancement expansion of depleted gas reservoir storage facilities.

The storage capacity and productivity of gas storage are affected by many factors, among which porosity and permeability are the main factors. To reveal the variation characteristics of porosity and permeability of different types of sandstone reservoirs in gas storage, five different types of sandstone samples were collected from the S gas storage in the Liaohe Depression, Bohai Bay Basin, and stress sensibility comparative experiments were carried out. The results show that the porosity and permeability decrease with the increase of effective stress, which affects the storage capacity and productivity of the gas storage. The porosity and permeability damage rate can be used to characterize the damage degree of the storage capacity and productivity. A damage factor characterizing storage capacity and productivity was proposed for the first time, which can be used to quantitatively evaluate storage capacity and productivity of gas storage under alternating load conditions. The porosity and permeability damage rate of the S gas storage increase linearly with the increase of effective stress. The porosity stress damage rate of the argillaceous siltstone reservoir is the largest, and the porosity stress damage rate of the medium-grained sandstone reservoir is the lowest. The argillaceous siltstone reservoir also has the largest permeability damage rate and its own permeability is too low, so it contributes less during emergency supply assurance. The medium-grained sandstone reservoir has the smallest permeability damage rate, and it has little influence on the capacity of peak regulating and supply assurance. Through this study, the quantified damage degree of stress to gas storage capacity was determined. According to the damage rate of different types of reservoirs, the storage capacity and productivity of gas storage can be maximized by optimizing the operation condition of gas storage reasonably.

The structure of caprocks is often greatly altered by different scales of faults or fissures in long-term geological tectonic evolution, and the sealing performance may be deteriorated. In this paper, a simplified geological model characterized as multilayered sandstone and fault-bearing caprocks extracted from the Shuang 6 underground gas storage located in the Liaohe oilfield was established. Different fault geometry (e.g., fault length, fault dip angle, and fault type) and seepage attributes (porosity and permeability) were considered to illustrate their impacts on natural gas migration during the cyclic high rate of injection and production of natural gas. The results showed that the seepage anisotropy and the natural gas front are strongly affected by the formation properties and, especially, are hindered by the low permeability sandstone layers. The difference in the lateral migration distance of natural gas in different layers can reach 110 m at the end of the injection period, with an annual injection volume of 108 m3. The migration of natural gas along the fault zone is mainly controlled by the permeability of faults, followed by fault scale, fault dip angle, and fault type. The sealing failure of caprocks in the fault zone does not occur based on the simulated gas migration distribution, showing that a very limited amount of natural gas migrates into the caprocks.

Wufeng Formation shale is an important source rock of unconventional hydrocarbons in the Lower Paleozoic shales of Sichuan Basin. However, the study on its provenance and paleoclimate is still relatively limited. In this study, mineralogical and geochemical data of the shales from the Upper Ordovician Wufeng Formation in southwestern China has been used to interpret the provenance and conditions of weathering and paleoclimate. The Wufeng shales have intermediate to high SiO 2 (57.72–82.38 wt. %, av. = 68.84 wt. %) and Al 2 O 3 (5.26–16.17 wt. %, av. = 10.62 wt. %), are rich in transition metal elements (i.e. V, Ni, Cu, Co and Cr) and Y as well as moderate depletion in Na 2 O and Sr, relative to the concentrations of the upper continental crust (UCC). In the chondrite-normalized (CN) rare earth elements (REE) distributions, these rocks display light REE (LREE) enrichment (La/Yb CN = 6.69–12.63, av. = 9.28), flat heavy REE (HREE) (Gd/Yb CN = 1.35–2.41, av. = 1.70), and clearly negative Eu anomalies (Eu an = 0.50–0.66, av. = 0.58), showing similar characteristics with the CN post-Archean Australian Average Shales (PAAS). Wufeng Formation shales are immature composition without evident recycling sediments, and they are originated from an intermediate-felsic igneous source composed of tonalite–trondhjemite–granodiorite (TTG), granitic and andesitic igneous rocks. The chemical weathering conditions of studied shales decreased from moderate to low in the provenance region, suggesting a gradual cooling trend of the climate at Late Ordovician Thus, this article will be helpful to discern the provenance and variations of chemical weathering conditions and paleoclimate of Wufeng Formation shales.

The underground gas storage (UGS) in depleted sandstone reservoirs forms the largest proportion of the UGS market in China. Multiple cycles of natural gas injection and production in the sandstone cause the rapid increase and drawdown of pore pressure, which may induce damage to the rock skeleton structure, and cause complex fluid flow paths in the sandstone reservoir. In this paper, transverse relaxation time (T-2), nuclear magnetism resonance imaging, and high-pressure mercury intrusion analysis are combined to evaluate the variation in pore structure of medium-grained sandstone. The results show that cyclic injection and production of fluid leads to a slight increase in total pore volume, indicating that weak damage to rocks occurs. The T-2 spectrum at the low pore pressure (10 MPa) and high pore pressure (25 MPa) both show that the shrinkage of the medium-size pores occurs after multiple cycles of injection and production. The pore volume of large-size pores was not highly correlated with the number of cycles. With the increase in pore pressure, the pore volume ratio under high pore pressure increased with the number of cycles, while it fluctuated strongly under low pore pressure.

Great progress has been made in the exploration of tight sandstone gas resources in Kuqa depression. Great progress has been made in Dibei structural belt, which proves the previously unproven favorable area for tight sandstone gas. The physical properties, controlling factors, and characteristics of tight sandstone from the Ahe (J1a) Formation in the Dibei gas reservoir are analyzed. The results show that the tight sandstone of the J1a Formation is mainly feldspar lithic sandstone, with low porosity (average 9.1%) and low permeability (average 0.09 mD). Compaction (average compaction rate 61.9%) reduces porosity more than cementation (average cementation rate 14.3%). Secondary dissolution pores (average thin section porosity is 3.4%) dominate. The homogenization temperature has two peaks; the first peak is 85–110 °C, and the other peak is 115–140 °C, indicating that oil and gas experienced two filling stages at 12 Ma and 4.5 Ma, respectively. Eodiagenesis, A substage of mesogenetic diagenesis, and B substage of mesogenetic diagenesis happened in the area. Tight sandstone is developed in the B substage of mesogenetic diagenesis. The main controlling factors of diagenesis are: strong dissolution and structural pore increase; oil and gas charging and overpressure. The reservoir forming mode of the Dibei gas reservoir is: crude oil filling in the Late Neogene (12 Ma); reservoir densification in the late deposition of Kangcun Formation (7 Ma), mature natural gas filling in the early deposition of Kuqa Formation (4.5 Ma), and gas reservoir formed after transformation and adjustment in the deposition period of Quaternary (2 Ma). According to this model, it is predicted that the favorable area of the Dibei gas reservoir is in the southeast of the Yinan 2 well. This study provides guidance for the study of tight sandstone gas in other areas of the Kuqa Depression.

[研究目的]塔里木盆地台盆区中寒武统发育大面积的膏盐岩、膏质泥岩和膏质云岩地层,探讨该套地层的油气封盖能力和展布可为塔里木盆地寒武系盐下领域的勘探提供依据.[研究方法]对4口井的44个岩心样品进行镜下薄片、物性参数和突破压力测试.通过建立各参数之间的关系,定量地对研究区中寒武统不同岩性岩石的封盖能力进行评价;结合二维地震和14口钻井资料对研究区中寒武统膏盐岩、膏质泥岩和膏质云岩地层的厚度进行研究;最终综合研究区中寒武统微观和宏观的评价结果,并以实际钻井的勘探情况作为约束,建立针对该研究区盖层封盖能力的综合评价方式.[研究结果]研究结果认为膏盐岩相比膏质泥岩与膏质云岩具有更好的封盖能力,但断裂和石膏的埋藏地质条件会影响盖层的封盖能力.其中阿瓦提凹陷、塔中隆起北部、满西低凸起南部以及巴楚隆起中北部膏盐岩盖层厚度较大,以巴楚隆起北部为中心,膏盐岩厚度向四周呈不规则状递减,环绕状分布.[结论]认为阿瓦提凹陷、满西低凸起西部和南部、塔中隆起北部和西部,以及塔北隆起中部为盖层发育的有利区.

库车坳陷东部油气地质条件复杂,天然气成因与油气充注时间存在争议,油气充注史不明,制约其油气勘探进程.利用天然气组分、碳同位素组成、流体包裹体岩相学与均一温度等分析测试数据,结合沉积埋藏史及构造演化史,研究了库车坳陷东部吐格尔明地区天然气地球化学特征、天然气成因类型及油气充注时间,分析了油气充注成藏过程.结果表明:吐格尔明地区天然气组分以甲烷为主,甲烷含量为75.56％～90.11％,干燥系数为0.79～0.93;δ13C1和δ13C2值为-35.73‰～-33.80‰和-26.41 ‰～-25.30‰,天然气成因类型属于成熟阶段的煤成气.吐格尔明地区侏罗系砂岩储层发育两类流体包裹体,分别为黄色液态烃包裹体和蓝白色荧光的气液烃包裹体、灰色的气烃包裹体,表明该区存在两期油气充注,第一期为13～7 Ma的原油充注,第二期为2.6 Ma以来的天然气充注.康村组早中期,吐格尔明地区烃源岩形成的原油充注至宽缓背斜圈闭中保存;库车组晚期,侏罗系克孜勒努尔组与阳霞组发育良好的源储组合,天然气近距离充注成藏.

The tectonic belt in northern Kuqa Depression has a long period of fault activity and multi-stage superposition, which has an important influence on hydrocarbon accumulation.Through the combination of growth index profile method, typical profile elongation (or compression ratio) method and structural equilibrium profile method, the development characteristics, active periods and hydrocarbon accumulation significance of faults in the northern Kuqa Depression are studied.The results show that there are three types of faults in the northern Kuqa Depression: early thrust fault, late thrust fault and long-term active fault.There are five periods of fault activity, which are paleogene (E), Neogene Jidike Formation (N1j), Kangcun Formation (N1k), Kuqa Formation (N2k) and Quaternary (Q) respectively.N1j, N1k and N2k are the key periods of fault activity.The fault activity will lead to the thickening of the source rocks in the Kezilenuer Formation (J2kz), which is conducive to the formation of multiple types of structural and lithologic traps.The fault active periods (N1j, N1k, N2k) match well with the main hydrocarbon generation and expulsion periods (E, N1j, N1k, N2k) of source rocks.The fault activity is beneficial to the formation and accumulation of oil and gas reservoir Yinan 2 and Tundong 2, but it also lead to the escape of oil and gas escape from Yinan 4 and Yishen 4 Wells, resulting in the destruction of reservoir forming and preservation conditions.The fingdings are of great significance to the analysis of hydrocarbon accumulation process in this area.

Because of the huge potential of hydrocarbon, the Jurassic strata in the Tugeerming area has become a significant exploration target in the Kuqa Depression of the Tarim Basin. However, accumulation characteristics and controlling factors for the Tugeerming gas reservoir need to be further developed. In the present study, the accumulation characteristics were discussed using geochemical techniques, and the controlling factors for the generation and accumulation of gas reservoir were summarized. The gas generation intensity in Tugeerming reservoir is about 20-60 x 10(8) m(3)/km(2), suggesting that source rocks could generate sufficient natural gas for the reservoir. Sandstone reservoirs with relatively good physical properties (Improved by fractures and dissolution) provide favorable condition for the gas accumulation. This oil charging period of the Early Neogene (N(1)j) and the gas charging period of the Pliocene (N(2)k) occurred in the reservoir and the periods were 23-8 Ma and 5.2-1.64 Ma, respectively. Continuous production of natural gas is beneficial to accumulation. Faults and fractures provide migration channels for oil and gas. Fractures optimize the physical properties of the reservoir. Moreover, the assemblages of source-reservoir-caprock in Tugeerming area provided good condition for hydrocarbon preservation. Tugeerming gas reservoir is defined as a structure-lithologic type, which is lower generation and upper storage mode. The conclusions are critical to further oil and gas exploration.

Intra-platform carbonate mound-bank body reservoirs is an important type of oil and gas reservoirs in the Sichuan Basin, and paleo-uplift plays an important role in the scale formation process of scale intra-platform mound-bank body reservoir. So far, however, the control action of paleo-uplift on the formation and distribution of intra-platform mound-bank body reservoirs has not been understood clearly enough, which restricts the oil and gas exploration progress of this type of reservoirs. In order to provide the basis for oil and gas exploration deployment, this paper analyzes the formation and evolution of four paleo-uplifts developed in the cratonic stage of the Sichuan Basin. On this basis, the genetic mechanisms and characteristics of scale intra-platform mound-bank body reservoirs are studied, and the characteristics and distribution of large-scale intra-platform reservoirs in the main series of strata are analyzed. And the following research results were obtained. First, the four paleo-uplifts developed in the Sichuan Basin plays an important constructive role in the formation of scale intra-platform mound-bank body reservoirs. Their control actions mainly include sedimentation and diagenesis. Along with the sea level change, they control the sedimentation scale and distribution range of intra-platform mound-bank body. They control the interlayer karstification and quasi-syngenetic dolomitization of intra-platform mound-bank body. And together with the late tectonic movement, they control the weathering crust karstification and fracturing of intra-platform mound-bank body. Second, Gaoshiti-Moxi paleo-uplift mainly controls the formation of the large-scale intra-platform mound-bank body reservoirs in the Sinian Dengying Formation and the Cambrian Longwangmiao Formation, Leshan-Longnüsi paleo-uplift mainly controls the formation of the scale intra-platform mound-bank body reservoir in the Cambrian Xixiangchi Formation and the Carboniferous Huanglong Formation, while Luzhou and Kaijiang paleo-uplifts mainly control the formation of the scale intra-platform mound-bank body reservoirs in the Triassic Jialingjiang Formation and Leikoupo Formation. Third, six sets of scale intra-platform reservoirs are developed in the Sichuan Basin. The intra-platform mound-bank body reservoirs of Dengying Formation and Longwangmiao Formation are mainly distributed in the core of paleo-uplift, and the other four sets are mainly distributed in the slope of paleo-uplift. In conclusion, these research results provide the geological basis for the prediction of scale intra-platform mound-bank body reservoirs in the Sichuan Basin and they are of important theoretical and practical significance.

通过对重矿物特征、不同成因石英阴极发光特性及古流向分析,探讨侏罗纪南天山构造带差异隆升对库车拗陷"源-汇"系统的影响.库车拗陷侏罗系重矿物组合特征、石英阴极发光特征平面上表现出明显的东西方向分异性;古流向主要为近南北方向;物源主要来自南天山造山带岩浆岩及变质岩,少量来自沉积岩;侏罗纪南天山存在多期强烈构造挤压和隆升,南天山构造活动具有明显的分段性和继承性,且东段隆升时间早于西段.南天山东早西晚的构造隆升控制了物源及古水流体系的变化,东段构造活动更为频繁、强烈,并导致了较大的地形起伏,在东段及其所对应的拗陷区发育多个相对独立的古水系.

Material exploration discoveries have been achieved in the Middle Triassic Leikoupo Formation in the Sichuan Basin in recent years, and a large-scale reservoir is one of the key factors controlling reservoir formation. In this paper, the lithofacies paleogeographic map of the Leikoupo Formation is prepared based on field outcrops, exploratory wells, well logs, and seismic data. The characteristics of large-scale reservoirs have been analyzed, which resulted in three new summarized understandings: (1) At the Leikoupo stage, the Sichuan Basin was relatively closed in the south, east and north, and the seawater entered through the west side, so it was a relatively closed carbonate platform; during the sedimentary stage of Lei I and Lei II members, it was a weakly fringed carbonate platform. In the sedimentary period of Lei III (T2l3) and Lei IV (T2l4) members, it was a rimmed carbonate platform. (2) The sedimentary facies including the platform margin, open platform, restricted platform, and evaporative platform were developed in the Leikoupo Formation; these were mainly the restricted platform facies covering the subfacies of the lagoon, intra-platform shoal, and tidal flat. Two types of hydrocarbon reservoirs, namely the platform-margin shoal and intra-platform shoal reservoirs, were developed in this period. (3) Two sets of large-scale reef beach facies reservoirs were developed in the Leikoupo Formation, one is the platform margin reef beach facies of Lei III (T2l3) and Lei IV (T2l4) members in northwestern Sichuan with a large thickness (generally larger than 50 m); the other one is the intra-platform shoal facies in the lower part of Lei I Member (T2l1) in Central Sichuan with a small thickness, stable distribution, and a large area (larger than 20,000 km2) forming large-scale reservoirs. The two types of large-scale reservoirs experienced multi-stage karstification transformation to become reservoirs with a good quality, laying the material basis for large-scale oil & gas reservoir formation. The research results have important theoretical and practical significance to improve the understanding on the sedimentation and reservoirs of the Leikoupo Formation in the Sichuan Basin, and to provide guidance for the oil and gas exploration in this region.