Well Yuetan 1H in the Taipei Sag of the Tuha Basin made the first exploration discovery in the Badaowan Formation of the Xiaocaohu sub-sag, which achieved a comprehensive breakthrough in the exploration of the secondary sag area of the Taipei Sag and revealed the good exploration prospect of tight sandstone gas in the entire Taipei Sag area. Based on the Taipei Sag, this paper comprehensively analyzes the geological conditions of deep tight sandstone gas formation, and concludes that: (1) the development of three sets of source rocks in the Shuixigou Group provides a sufficient material basis for tight sandstone gas; (2) The development of delta front-scale sand bodies and near-coal seam sandstone dissolution pores are favorable reservoirs for deep tight gas accumulation; (3) The strata located in the lower part of the strike-slip thrust zone have good preservation conditions, which is a favorable area for tight sandstone gas enrichment. At the same time,based on the geological information obtained from the exploration and discovery of Well Yuetan 1H, the dominant accumulation conditions of Xiaocaohu sub-sag were clarified, and then the favorable geological conditions of tight gas in the entire Taipei Sag were re-understood, and it was pointed out that: (1) effective sand bodies were developed in the central area of the sub-sag; (2) The physical properties of the reservoir of the southern source sand body are better; (3) The source rock development zone with higher maturity is a favorable zone for natural gas enrichment. Based on the latest geological information and understanding, the evaluation of tight gas resources in Taipei Sag was re-carried out, and the predicted tight sandstone gas resources were 7070×10⁸m³, which was significantly higher than that in the previous period. Finally, the comprehensive evaluation selects two favorable exploration areas of tight sandstone gas in the northeast of Xiaocaohu sub-sag and north of Shengbei sub-sag.

There are abundant shale oil resources in the seventh member of Yanchang Formation (Chang 7 member) in Ordos Basin. The largescale interlayered type shale oil reserves have been discovered in the first-second sub-member of Chang 7 member (Chang 7_1-2 sub-member), marking a major breakthrough in the exploration and development of continental shale oil. However, there is a low level of systematic study and evaluation of new type shale oil in the third sub-member of Chang 7 member (Chang 7₃ sub-member). By using SEM, 2D NMR, full field fluorescent thin section, and infrared spectroscopy analysis, as well as identification and evaluation techniques such as geophysical exploration and logging, geological understanding and oil enrichment mechanisms are summarized. The analysis shows that: (1) The laminated shale is composed of felsic-rich lamina, organic-rich lamina, tuffaceous-rich lamina, and clay-rich lamina. The pore type is dominated by intergranular pores, dissolution pores, and intercrystal pores, with a porosity of 2%–10% and an oil saturation of 68%–88%. (2) The mud laminar type shale is composed of clayey felsic siltstone, clayey felsic mudstone, and felsic clayey shale. The pore type mainly includes dissolution pores, intercrystal pores, and bedding fractures, with a porosity of 2%–6% and an oil saturation of 65%–75%. (3) The crude oil generated by organicrich shale in Chang 7₃ sub-member was retained and accumulated, and also accumulated in felsic-rich siltstone after micro migration, showing hydrocarbon retention–micro migration and enrichment pattern. The predicted favorable zone of laminated type shale oil in Chang 7₃ submember is 5000 km², and that of mud laminar type shale oil is 1600 km², with predicted reserves of up to one hundred million tons, showing huge exploration potential.

Ghardaia area, located in the northern Algeria, is a prolific zone in Oued Mya Basin, showing great potential for the exploration and development of oil and gas resources. It is necessary to conduct a systematic study of the petroleum geological characteristics and hydrocarbon accumulation rules, as well as the exploration potential in this area, which has important significance for investing in the Algerian oil and gas business of Chinese oil and gas enterprises. Based on the comprehensive study of geological, geochemical, and relevant literature data of Oued Mya Basin, a detailed analysis of controlling factors for hydrocarbon accumulation has been conducted, including the distribution of source rocks and their hydrocarbon generation potential, reservoir distribution, and hydrocarbon accumulation timing and rules. In addition,some geological maps have been prepared for the main source rocks, reservoirs, and hydrocarbon accumulation patterns, and the hydrocarbon generation potential has been calculated. Furthermore, the hydrocarbon accumulation combination and migration rules have been analyzed. The study results show that a set of high-quality source rock with high organic abundance was developed at the base Silurian, which was dominated by oil generation in the northeastern basin and gas generation in the southern basin, and the primary hydrocarbon kitchen was located in the southeastern part of the study area. The main reservoirs include A sand group in T2 Formation and B sand group in T2 Formation in the Middle Triassic, and the Ordovician Harmar Formation quartz sandstone. The vertical hydrocarbon migration occurred through faults connecting to source rock and then migrated laterally along the Triassic transport layer. As a result, the hydrocarbon accumulation pattern of “hydrocarbon supply by mature shale, long-distance migration, and late-stage enrichment”. The future exploration efforts should focus on structural traps of the Triassic A sand group, while simultaneously emphasizing the exploration of the Triassic B sand group, as well as the Ordovician tight reservoir and shale oil and gas.

High-quality reservoirs with high-yield oil flow are still developed in the deep saline lake basin (burial depth>4500 m) in Zahaquan area, Qaidam Basin. But there are significant differences in the physical properties of clastic rock reservoirs at similar burial depths. In order to clarify the main controlling factors for reservoir physical properties and the lower limit of effective reservoir thickness in saline lake basins, Upper Ganchaigou Formation in Zhahaquan area is studied in this paper. By comprehensively using experimental methods such as core observation, cast thin section identification, rock physical properties test, and mercury injection test, comparative analysis is conducted on reservoir performance of sand bodies with various sedimentary microfacies. The study results show that sand bodies of shallow shore lake beach bar microfacies in Zhahaquan area are subdivided into three types, i.e., bar main sand, bar edge sand, and beach sand. The reservoir space is dominated by primary pores, and the bar main sand has the best reservoir performance, followed by bar edge sand and beach sand. The compaction and cementation were the main diagenetic processes that caused pore loss in reservoirs. The compaction degree of reservoirs of the same microfacies was equivalent, while the difference in cementation strength generally led to the variation in physical properties of beach bar sand reservoirs with various thicknesses and the heterogeneity of single beach bar sand reservoir. The high-quality beach bar sand reservoirs in deep formations were jointly controlled by the original sedimentary hydrodynamic conditions, early cementation, early oil and gas charging, and early slow and late rapid burial history. After clarifying the lower limit of conventional effective reservoir porosity, which is 8%, it is predicted that the lower limit of effective thickness for silty to fine-grained beach bar sand reservoirs is 1 m, and that for medium- to finegrained beach bar sand reservoirs is 0.5 m.

Breakthroughs have been made in the exploration of carbonate oil reservoirs in Qianjiang salt lake basin, but the tested oil production and steady production effects vary among wells. As a result, a comprehensive study is conducted on core (a length of more than 200 m), thin section, rock pyrolysis, and porosity and permeability experiment data of Well H61X, as well as well testing data of six wells in Tankou bulge zone with abundant oil reservoir data, and the characteristics of carbonate oil reservoirs are analyzed to clarify the main controlling factors for the enrichment and high-yield production of this type of oil reservoirs. The study results indicate that the porosity of salt lake carbonate reservoir is 2.2%–12.4%, and the permeability is 0.15–3.13 mD, showing characteristics of low porosity, and low to ultralow permeability. Combined with the analysis of well testing results, it shows that more intercrystal pores are developed in the same type of carbonate rock with a high carbonate content, increasing the total reservoir space, and promoting oil and gas enrichment. The near-source traps are more conducive to hydrocarbon enrichment, and oil wells near sub-sag have higher daily oil production and steady production effects in the later stage. The reservoir thickness and crude oil properties affect the steady production effect of a single well, and the well has a good sustained steady production performance with a reservoir thickness of greater than 10 m and crude oil viscosity of less than 200 mPa·s. The “composite acid fracturing and sand adding” reservoir reconstruction technology enables to increase porosity and permeability, and enhance the conductivity of carbonate reservoirs, which is a key technology for increasing production of carbonate reservoirs. The lacustrine carbonate rocks show excellent oil production capacity and resource potential, which is an important exploration filed in Qianjiang Sag in the future.

The shale gas within the Deyang-An’gue sag, specifically in the Qiongzhushi Formation, exhibits significant exploration potential. The characterization of the sag’s depositional features during the sedimentary period of the Qiongzhushi Formation has not been systematically understood. By establishing a sequence stratigraphy framework for the deposition of the Qiongzhushi Formation and analyzing sedimentary landforms based on shale thickness and quality, the geological significance of shale gas is elucidated. The results indicate that, considering sedimentary landforms, sedimentary facies, shale thickness, etc., the sedimentary period of the Qiong 1-2 sub-section can be divided into three landform units: intra-sag, slope, and extra-sag. Ancient landforms and source materials jointly control the shale thickness and quality. The intra-sag unit develops a siliceous mud-shale microfacies, with a shale reservoir thickness exceeding 20 m. The slope unit develops (including) sandy mud-shale microfacies, with a shale reservoir thickness of 5 to 20 m. The extra-sag unit develops muddy sandy-shale microfacies, with a shale reservoir thickness less than 5 m.

The Carboniferous volcanic rock oil and gas reservoirs have abundant reserves in Shixi area, Junggar Basin, showing good exploration and development potential. However, there is a lack of clear understanding of stratigraphic framework system of the Carboniferous volcanic rocks, and lithofacies characteristics of various rhythmic layers, which restricts the optimal selection of vertical exploration layers in this area and the implementation of horizontal wells. The cores, thin sections, logging, and seismic data are comprehensively studied to construct stratigraphic framework and analyze the vertical lithofacies distribution in the Carboniferous in Shixi area. The seismic random simulation inversion of sensitivity curves (GR and CNL) and fusion technology are used to predict the distribution of volcanic rock lithofacies. The study results indicate that based on the principle of “cycle–stage–rhythm–lithofacies”, volcanic rocks in the Carboniferous Batamayineishan Formation are divided into three cycles (C₂b₁, C₂b₂, C₂b₃), and the upper two cycles are subdivided into four stages and eight rhythmic layers. From stage A1 to stage C1, the lithology shows a transition from intermediate basic rock–intermediate rock–intermediate acidic rock. The lithofacies of the Carboniferous volcanic rocks is divided into two types, i.e., explosive facies and overflow facies. The explosive facies is subdivided into thermal debris flow subfacies and air-fall flow subfacies, while the overflow facies is subdivided into intermediate basic overflow facies, intermediate overflow facies, and acidic overflow facies based on rock types. Vertically, the volcanic rocks of eruptive and overflow facies are superimposed from bottom to top, with a larger thickness of overflow facies than the eruptive facies, and a weakly continuous and dispersed lens-shaped eruptive facies within the overflow facies. The overflow facies in B1 and B2 stages were widely developed, and volcanic activity was dominated by overflow. In C1 stage, the overflow facies weakened and explosive facies strengthened, with explosive facies dominant. On the plane, the overflow facies in each stage has a relatively large thickness near the fault, gradually thinning towards the interior of the structure. The physical property analysis shows that the predominant lithofacies for reservoir development includes explosive facies and intermediate overflow facies. The study of plane lithofacies distribution in the framework of volcanic rhythmic layers provides a geological basis for the high-efficiency development of the Carboniferous volcanic oil reservoirs and well implementation in Shixi area, and serves as practical exploration and development case of similar oil and gas reservoirs.

Mixed shale oil reservoirs are characterized by diverse rock fabric and lithofacies types, significant differentiation in diagenetic evolution, strong heterogeneity in micro-pore structure, complex genetic mechanism of micro-pore and fracture system and effective storage and permeability space. Taking the mixed shale oil reservoir of Lucaogou Formation in Jimsal Depression as the research object, the diagenetic types and diagenetic facies types of the shale layer of Lucaogou Formation were defined and the differential rock formation and reservoir formation mechanism of the mixed shale oil reservoir was revealed by comprehensive analysis and testing methods such as cast thin section, field emission scanning electron microscopy, X-ray diffraction, high pressure mercury injection and nitrogen adsorption. The results show that the diagenesis types of mixed shale oil reservoirs in Lusaogou Formation are diverse, including compaction, cementation and dissolution. According to the key diagenetic types and characteristic fabric, diagenetic facies can be divided into tuffe-feldspar dissolution phase, mixed cementation dissolution phase, chlorite film dissolution phase, carbonate junction phase and mixed cementation compact phase. The dissolution phase of tuffaceous feldspar is dominated by the dissolution pores of feldspar and tuffaceous, which are mainly in the range of 50-800 nm, and the total pore volume is the largest, which is the result of partial or complete dissolution of feldspar particles. The combination of solution pores and residual intergranular pores is developed in the mixed cementation phase, mainly in the range of 50-400 nm. It is the result of the superposition of carbonate, siliceous cementation and feldspar dissolution, and the total pore volume is the largest. The cement phase of chlorite film is dominated by residual intergranular pores with small pore size, and pores less than 50 nm are dominant. The heterogeneity is the weakest in all diagenetic phases, and the total pore volume is in the middle in all diagenetic phases, which is the result of corrosion and anti-compaction. The development of intergranular solution pores in carbonate cementation phase is dominated by pores in the range of 20-50 nm, which is the result of dissolution and carbonate cementation. All kinds of pores in the dense phase of mixed cementation are not developed, mainly in the range of less than 50 nm, which is the result of the comprehensive failure of compaction and cementation. Tuffaceous feldspar dissolution phase, mixed cementation dissolution phase and chlorite film phase are the dominant diagenetic facies types, while carbonate cementation phase and mixed cementation dense phase are not conducive to forming good reservoir conditions. This understanding is conducive to further understanding the differential formation process and mechanism of mixed shale oil formations. This finding helps deepen the understanding of the differentiated reservoir-forming processes and mechanisms of mixed shale oil layers, serving the precise prediction and efficient exploration and development of favorable shale oil production areas in the Jimusar Depression.

There are multiple large-scale lithologic type gas reservoirs in the Middle Permian Maokou Formation in central Sichuan Basin, which is one of the major field for increasing reserves and production in Sichuan Basin. In view of the unclear genesis and evolution of formation water, as well as gas–water distribution pattern in Maokou Formation, a comprehensive study is conducted on experimental tests, well drilling, logging, seismic interpretation, and production performance data, which enables to systematically analyze the chemical characteristics of formation water, identify the origin, genesis and evolution, and further discuss the characteristics of gas–water distribution.The results show that formation water in Maokou Formation in central Sichuan Basin is CaCl₂ type, with a total salinity of 38.3–62.0 g/L, saltwater-brine type, and the main anion and cation of Cl^- and Na⁺. Maokou Formation in this area has good sealing capacity, which may have experienced short-period atmospheric precipitation and leaching. In addition, the formation water experienced high concentration and metamorphism, as well as intensive water-rock reactions, resulting in the development of secondary pores in the reservoir, which was a favorable zone for hydrocarbon migration and accumulation. The original formation water showed typical marine-derived formation water,and underwent water-rock reactions such as calcite cementation, dolomitization, and dissolution in addition to evaporation and concentration. After mixed with atmospheric freshwater, mudstone and clay mineral pressure release water, the common cation exchange adsorption occurred at varying degrees. The genesis and evolution of formation water were well correlated with reservoir diagenesis and natural gas migration, accumulation and preservation. In the study area, formation water has two distribution patterns, namely displacement residual water in the isolated fractured-cavity system and local edge–bottom water in layered reservoirs, with limited scale and energy of water bodies, and the water production is controllable in gas wells. The achievements provide theoretical support for accelerating the process of natural gas exploration and development of Maokou Formation, and seeking for replacement fields for increasing reserves and production on a large scale.

In recent years, a series of major oil and gas discoveries have been made in the Upper Cretaceous turbidite sandstones in Guyana Basin, which increases the confidence of further exploration. The primary issue facing the petroleum exploration includes the differences in hydrocarbon accumulation patterns in various zones and reservoir sections, as well as the further exploration orientations. After studying tectono-sedimentary evolution, hydrocarbon accumulation conditions, oil and gas distribution, hydrocarbon accumulation pattern and main controlling factors, the differences in hydrocarbon accumulation in various zones of Guyana Basin are systematically analyzed and the further exploration orientation is determined. The study results indicate that Guyana Basin experienced four major stages of tectonic evolution, i.e., pre-rift, early rift, late rift, and passive margin, and four deposition zones were divided in the basin, including coastal plain, continental shelf, continental slope, and deep-water basin. Two sets of effective hydrocarbon source rocks are developed in the Basin: high-quality marine source rocks of the Cenomanian Stage during the passive margin period, and lacustrine source rocks of the Upper Triassic to Lower Jurassic strata during the early and late rift stages. The distribution of oil and gas shows characteristics of “vertical layering” and “planar zoning”. The main hydrocarbon accumulation play was developed in the Upper Cretaceous in continental slope zone, such as the large-scale turbidite sandstone oil reservoirs. Three types of hydrocarbon accumulation models are classified as a whole, namely near-source hydrocarbon accumulation, lateral medium-distance hydrocarbon migration and accumulation, and lateral long-distance hydrocarbon migration and accumulation. The continental slope zone and deep-water basin zone are dominated by near-source hydrocarbon accumulation model, which is the main hydrocarbon accumulation model in the basin, and the enrichment of oil and gas is mainly controlled by high-quality reservoir. The continental shelf zone is mainly characterized by lateral medium-distance hydrocarbon migration and accumulation, and sealing capacity and reservoirs are the main controlling factors. The coastal plain zone is characterized by lateral long-distance hydrocarbon migration and accumulation model, with the main controlling factors including source rock, migration pathway, and densification mechanism. The further exploration should focus on turbidite sandstones in continental slope zone, and attach equal importance to oil and gas, with two important orientations in the northwest and northeast zones.

The geological conditions are complex in Baojing shale gas block, with characteristics of thin reservoir, great burial depth, and high degree of thermal evolution of the Lower Silurian Longmaxi Formation shale. The exploration and development of shale gas are facing great challenges and difficulties, and there is a lack of mature experience to learn from. Therefore, targeting at the goal of speed and efficiency improvement, the exploration mode of “three wells in one” has been applied, and research and practice of integrated well drilling technology have actively been conducted as follows: (1) Well location deployment. On the basis of seismic data inversion, seismic reservoir prediction and gas content detection are conducted. The vertical well is first drilled to obtain reservoir parameters and delineate favorable areas, and then the horizontal well is drilled to evaluate the shale gas production capacity. (2) Geological guidance model establishment. The cross well seismic and logging data are used to establish a geological guidance model before drilling, and then A-B marker bed is used to guide the bit drilling. (3) Implementation of integrated drilling. The upper well section is drilled by downhole screw drill tool to achieve the accurate control of wellbore trajectory. The rotary steering drilling system is applied to drill through the lower well section, and the interactive measurement and control technology is used to monitor the cutting of formation by the drill bit in real time, so as to ensure accurate guidance in the target window. The results show that the integrated well drilling technology enables to improve the drilling rate and accurately obtain formation geological parameters, which is conducive to reservoir evaluation, with a drilling rate of 3.81 m/h and a reservoir penetration rate of 90.68%. The implementation of “three wells in one” exploration mode accelarates the process of shale gas exploration and development. The integrated well drilling technology promotes the shale gas exploration progress in complex structural zone, achieves the low-cost and high-efficiency shale gas development, and provides a reference for shale gas exploration and development in similar areas.

At present, it is in an early exploration stage of coal measure reservoir in the Permian Longtan Formation in Qijiang area, southeastern Sichuan Basin. There is a lack of clear understanding of fracturing quality of complex lithologies and fracture propagation characteristics of interbedding of shale, limestone, and coal rock, which needs to be further studied. In response to the above issues, experimental tests, fracturing physical simulation, and numerical simulation are conducted to analyze the fracturing quality and fracture propagation characteristics of Longtan Formation reservoir. The results show that there are significant differences in lithology, mineral composition, rock mechanical and in-situ stress parameters vertically of Longtan Formation reservoirs in various regions, and the reservoir is characterized by low brittle mineral content and poor brittleness as a whole, with the horizontal stress difference reaching up to 2–6 MPa between different rock types, making it difficult to propagate transverse fractures. The physical simulation result shows that due to the influence of lithologic boundary and stress difference coefficient, three types of fractures are observed in Longtan Formation, i.e., T-shaped fractures, passivation fractures, and transverse fractures, and the fracture pattern is mainly controlled by the strength of lithologic boundary. The numerical simulation of fracture propagation characteristics shows that the displacement, viscosity, and fracture initiation position have a significant influence on fracture propagation pattern. On this basis, the shale interval and mudstone interval intercalated with limestone and shale layers are optimally selected, and fracturing operation is implemented with a displacement of higher than 12 m³/min and a fracturing fluid viscosity of about 25 mPa·s to promote the transvers propagation of hydraulic fractures.

The preliminary estimated resources of carbonate oil reservoirs in Qianjiang Sag are 3.7×10⁸ t, which are important replacement resources for the exploration and development of Jianghan Oilfield. However, due to the diverse lithologies and well-developed interlayers of oil reservoir in Qianjiang Sag, the early acid fracturing technology had poor implementation results, obtaining an average oil rate of 1.6 t/d after fracturing, and the effective rate of only 42.9%, which was unable to achieve effective resource utilization of the block. Therefore, it is necessary to study the geological–engineering characteristics of carbonate rocks with different lithologies and research differentiated measures and technologies. By analyzing and processing data such as well logging, mechanical testing, and mineral composition, some important relevant indicators are obtained, and the multiple linear regression method is used to establish the fracability evaluation model. In addition, two sub-members with good fracability are optimally selected as high-quality sweet spot layers, i.e., the fourth sub-member of the third member of the Paleogene Qianjiang Formation and the lower sub-member of the fourth member of the Paleogene Qianjiang Formation. The basic experimental research such as mechanical testing is conducted on core samples with various lithologies, which enables to identify fracture propagation laws of different carbonate rocks, determine the concept of differentiated reservoir reconstruction, and develop two sets of fracturing technologies, namely the acid fracturing composite sand addition technology for granular carbonate rocks and complex network fracturing technology for micritic carbonate rocks. The former technology has been applied for granular carbonate rocks in four wells, with an effective rate of 100%, and an average oil rate of 8.4 t/d, forming a good scene of increasing reserves with an amount of nearly 20 million tons. The complex network fracturing technology has successfully been applied in Well Z99X, with an oil rate of 137.6 m³/d by blowout testing with a 4 mm oil choke, marking a major breakthrough in new layers in new areas.