In addition to the organic matter type, abundance, thermal maturity, and shale reservoir space, the preservation conditions of source rocks play a key factor in affecting the quantity and quality of retained hydrocarbons in source rocks of lacustrine shale, yet this aspect has received little attention. This paper, based on the case analysis, explores how preservation conditions influence the enrichment of mobile hydrocarbons in shale oil. Research showns that good preservation conditions play three key roles. (1) Ensure the retention of sufficient light hydrocarbons (C₁-C₁₃), medium hydrocarbons (C₁₄-C₂₅) and small molecular aromatics (including 1-2 benzene rings) in the formation, which enhances the fluidity and flow of shale oil; (2) Maintain a high energy field (abnormally high pressure), thus facilitating the maximum outflow of shale oil; (3) Ensure that the retained hydrocarbons have the miscible flow condition of multi-component hydrocarbons (light hydrocarbons, medium hydrocarbons, heavy hydrocarbons, and heteroatomic compounds), so that the heavy hydrocarbons (∑C₂₅₊) and heavy components (non-hydrocarbons and asphaltenes) have improved fluidity and maximum flow capacity. In conclusion, in addition to the advantages of organic matter type, abundance, thermal maturity, and reservoir space, good preservation conditions of shale layers are essential for the formation of economically viable shale oil reservoirs, which should be incorporated into the evaluation criteria of shale oil-rich areas/segments and considered a necessary factor when selecting favorable exploration targets.

By reviewing the research progress and exploration practices of shale gas geology in China, analyzing and summarizing the geological characteristics, enrichment laws, and resource potential of different types of shale gas, the following understandings have been obtained: (1) Marine, transitional, and lacustrine shales in China are distributed from old to new in geological age, and the complexity of tectonic reworking and hydrocarbon generation evolution processes gradually decreases. (2) The sedimentary environment controls the type of source-reservoir configuration, which is the basis of “hydrocarbon generation and reservoir formation”. The types of source-reservoir configuration in marine and lacustrine shales are mainly source-reservoir integration, with occasional source-reservoir separation. The configuration types of transitional shale are mainly source-reservoir integration and source-reservoir symbiosis. (3) The resistance of rigid minerals to compression for pore preservation and the overpressure facilitate the enrichment of source-reservoir integrated shale gas. Good source reservoir coupling and preservation conditions are crucial for the shale gas enrichment of source-reservoir symbiosis and source-reservoir separation types. (4) Marine shale remains the main battlefield for increasing shale gas reserves and production in China, while transitional and lacustrine shales are expected to become important replacement areas. It is recommended to carry out the shale gas exploration at three levels: Accelerate the exploration of Silurian, Cambrian, and Permian marine shales in the Upper-Middle Yangtze region; make key exploration breakthroughs in ultra-deep marine shales of the Upper-Middle Yangtze region, the new Ordovician marine shale strata in the North China region, the transitional shales of the Carboniferous and Permian, as well as the Mesozoic lacustrine shale gas in basins such as Sichuan, Ordos and Songliao; explore and prepare for new shale gas exploration areas such as South China and Northwest China, providing technology and resource reserves for the sustainable development of shale gas in China.

Coal measures are significant hydrocarbon source rocks and reservoirs in petroliferous basins. Many large gas fields and coalbed methane fields globally are originated from coal-measure source rocks or accumulated in coal rocks. Inspired by the discovery of shale oil and gas, and guided by “the overall exploration concept of considering coal rock as reservoir”, breakthroughs in the exploration and development of coal-rock gas have been achieved in deep coal seams with favorable preservation conditions, thereby opening up a new development frontier for the unconventional gas in coal-rock reservoirs. Based on the data from exploration and development practices, a systematic study on the accumulation mechanism of coal-rock gas has been conducted. The mechanisms of “three fields” controlling coal-rock gas accumulation are revealed. It is confirmed that the coal-rock gas is different from CBM in accumulation process. The whole petroleum systems in the Carboniferous-Permian transitional facies coal measures of the eastern margin of the Ordos Basin and in the Jurassic continental facies coal measures of the Junggar Basin are characterized, and the key research directions for further developing the whole petroleum system theory of coal measures are proposed. Coal rocks, compared to shale, possess intense hydrocarbon generation potential, strong adsorption capacity, dual-medium reservoir properties, and partial or weak oil and gas self-sealing capacity. Additionally, unlike other unconventional gas such as shale gas and tight gas, coal-rock gas exhibits more complex accumulation characteristics, and its accumulation requires a certain coal-rock play form lithological and structural traps. Coal-rock gas also has the characteristics of conventional fractured gas reservoirs. Compared with the basic theory and model of the whole petroleum system established based on detrital rock formations, coal measures have distinct characteristics and differences in coal-rock reservoirs and source-reservoir coupling. The whole petroleum system of coal measures is composed of various types of coal-measure hydrocarbon plays with coal (and dark shale) in coal measures as source rock and reservoir, and with adjacent tight layers as reservoirs or cap or transport layers. Under the action of source-reservoir coupling, coal-rock gas is accumulated in coal-rock reservoirs with good preservation conditions, tight oil/gas is accumulated in tight layers, conventional oil/gas is accumulated in traps far away from sources, and coalbed methane is accumulated in coal-rock reservoirs damaged by later geological processes. The proposed whole petroleum system of coal measures represents a novel type of whole petroleum system.

Based on petroleum exploration and new progress of oil and gas geology study in the Qiongdongnan Basin, combined with seismic, logging, drilling, core, sidewall coring, geochemistry data, a systematic study is conducted on the source, reservoir-cap conditions, trap types, migration and accumulation characteristics, enrichment mechanisms, and reservoir formation models of ultra-deep water and ultra-shallow natural gas, taking the Lingshui 36-1 gas field as an example. (1) The genetic types of the ultra-deep water and ultra-shallow natural gas in the Qiongdongnan Basin include thermogenic gas and biogenic gas, and dominated by thermogenic gas. (2) The reservoirs are mainly composed of the Quaternary deep-water submarine fan sandstone. (3) The types of cap rocks include deep-sea mudstone, mass transport deposits mudstone, and hydrate-bearing formations. (4) The types of traps are mainly lithological, and also include structural- lithological traps. (5) The migration channels include vertical transport channels such as faults, gas chimneys, fracture zones, and lateral transport layers such as large sand bodies and unconformity surfaces, forming a single or composite transport framework. A new natural gas accumulation model is proposed for ultra-deep water and ultra-shallow layers, that is, dual source hydrocarbon supply, gas chimney and submarine fan composite migration, deep-sea mudstone-mass transport deposits mudstone-hydrate-bearing strata ternary sealing, late dynamic accumulation, and large-scale enrichment at ridges. The new understanding obtained from the research has reference and enlightening significance for the next step of deepwater and ultra-shallow layers, as well as oil and gas exploration in related fields or regions.

The basic geological characteristics of the Qiongzhusi Formation reservoirs and conditions for shale gas enrichment and high-yield were studied by using methods such as mineral scanning, organic and inorganic geochemistry, breakthrough pressure, and triaxial mechanics testing based on the core, logging, seismic and production data. (1) Both types of silty shale, rich in organic matter in deep water and low in organic matter in shallow water, have good gas bearing properties. (2) The brittle mineral composition of shale is characterized by comparable feldspar and quartz content. (3) The pores are mainly inorganic pores with a small amount of organic pores. Pore development primarily hinges on a synergy between felsic minerals and total organic carbon content (TOC). (4) Dominated by Type I organic matters, the hydrocarbon generating organisms are algae and acritarch, with high maturity and high hydrocarbon generation potential. (5) Deep-and shallow-water shale gas exhibit in-situ and mixed gas generation characteristics, respectively. (6) The basic law of shale gas enrichment in the Qiongzhusi Formation was proposed as “TOC controlled accumulation and inorganic pore controlled enrichment”, which includes the in-situ enrichment model of “three highs and one over” (high TOC, high felsic mineral content, high inorganic pore content, overpressured formation) for organic rich shale represented by Well ZY2, and the in-situ + carrier-bed enrichment model of “two highs, one medium and one low” (high felsic content, high formation pressure, medium inorganic pore content, low TOC) for organic-poor shale gas represented by Well JS103. It is a new type of shale gas that is different from the Longmaxi Formation, enriching the formation mechanism of deep and ultra-deep shale gas. The deployment of multiple exploration wells has achieved significant breakthroughs in shale gas exploration.

Significant exploration progress has been made in ultra-deep clastic rocks in the Kuqa Depression, Tarim Basin, over recent years. A new round of comprehensive geological research has formed four new understandings: (1) Establish structural model consisting of multi-detachment composite, multi-stage structural superposition and multi-layer deformation. Multi-stage structural traps are overlapped vertically, and a series of structural traps are discovered in underlying ultra-deep layers. (2) Five sets of high-quality large-scale source rocks of three types of organic phases are developed in the Triassic and Jurassic systems, and forming a good combination of source-reservoir-cap rocks in ultra-deep layers with three sets of large-scale regional reservoir and cap rocks. (3) The formation of large oil and gas fields is controlled by four factors which are source, reservoir, cap rocks and fault. Based on the spatial configuration relationship of these four factors, a new three-dimensional reservoir formation model for ultra-deep clastic rocks in the Kuqa Depression has been established. (4) The next key exploration fields for ultra-deep clastic rocks in the Kuqa Depression include conventional and unconventional oil and gas. The conventional oil and gas fields include the deep multi-layer oil-gas accumulation zone in Kelasu, tight sandstone gas of Jurassic Ahe Formation in the northern structural zone, multi-target layer lithological oil and gas reservoirs in Zhongqiu-Dina structural zone, lithologic-stratigraphic and buried hill composite reservoirs in south slope and other favorable areas. Unconventional oil and gas fields include deep coal rock gas of Jurassic Kezilenuer and Yangxia formations, Triassic Tariqike Formation and Middle-Lower Jurassic and Upper Triassic continental shale gas. The achievements have important reference significance for enriching the theory of ultra-deep clastic rock oil and gas exploration and guiding the future oil and gas exploration deployment.

Based on recent advancements in shale oil exploration within the Ordos Basin, this study presents a comprehensive investigation of the paleoenvironment, lithofacies assemblages and distribution, depositional mechanisms, and reservoir characteristics of shale oil of fine-grained sediment deposition in continental freshwater lacustrine basins, with a focus on the Chang 7₃ sub-member of Triassic Yanchang Formation. The research integrates a variety of exploration data, including field outcrops, drilling, logging, core samples, geochemical analyses, and flume simulation. The study indicates that: (1) The paleoenvironment of the Chang 7₃ deposition is characterized by a warm and humid climate, frequent monsoon events, and a large water depth of freshwater lacustrine basin. The paleogeomorphology exhibits an asymmetrical pattern, with steep slopes in the southwest and gentle slopes in the northeast, which can be subdivided into microgeomorphological units, including depressions and ridges in lakebed, as well as ancient channels. (2) The Chang 7₃ sub-member is characterized by a diverse array of fine-grained sediments, including very fine sandstone, siltstone, mudstone and tuff. These sediments are primarily distributed in thin interbedded and laminated arrangements vertically. The overall grain size of the sandstone predominantly falls below 62.5 μm, with individual layer thicknesses of 0.05-0.64 m. The deposits contain intact plant fragments and display various sedimentary structure, such as wavy bedding, inverse-to-normal grading sequence, and climbing ripple bedding, which indicating a depositional origin associated with density flows. (3) Flume simulation experiments have successfully replicated the transport processes and sedimentary characteristics associated with density flows. The initial phase is characterized by a density-velocity differential, resulting in a thicker, coarser sediment layer at the flow front, while the upper layers are thinner and finer in grain size. During the mid-phase, sliding water effects cause the fluid front to rise and facilitate rapid forward transport. This process generates multiple “new fronts”, enabling the long-distance transport of fine-grained sandstones, such as siltstone and argillaceous siltstone, into the center of the lake basin. (4) A sedimentary model primarily controlled by hyperpynal flows was established for the southwestern part of the basin, highlighting that the frequent occurrence of flood events and the steep slope topography in this area are primary controlling factors for the development of hyperpynal flows. (5) Sandstone and mudstone in the Chang 7₃ sub-member exhibit micro-and nano-scale pore-throat systems, shale oil is present in various lithologies, while the content of movable oil varies considerably, with sandstone exhibiting the highest content of movable oil. (6) The fine-grained sediment complexes formed by multiple episodes of sandstones and mudstones associated with density flow in the Chang 7₃ formation exhibit characteristics of “overall oil-bearing with differential storage capacity”. The combination of mudstone with low total organic carbon content (TOC) and siltstone is identified as the most favorable exploration target at present.

Based on the experimental results of casting thin section, low temperature nitrogen adsorption, high pressure mercury injection, nuclear magnetic resonance T₂ spectrum, contact angle and oil-water interfacial tension, the relationship between pore throat structure and crude oil mobility characteristics of full particle sequence reservoirs in the Lower Permian Fengcheng Formation of Mahu Sag, Junggar Basin, are revealed. (1) With the decrease of reservoir particle size, the volume of pores connected by large throats and the volume of large pores show a decreasing trend, and the distribution and peak ranges of throat and pore radius shift to smaller size in an orderly manner. The upper limits of throat radius, porosity and permeability of unconventional reservoirs in Fengcheng Formation are approximately 0.7 μm, 8% and 0.1×10^?3 μm², respectively. (2) As the reservoir particle size decreases, the distribution and peak ranges of pores hosting retained oil and movable oil are shifted to a smaller size in an orderly manner. With the increase of driving pressure, the amount of retained and movable oil of the larger particle reservoir samples shows a more obvious trend of decreasing and increasing, respectively. (3) With the increase of throat radius, the driving pressure of reservoir with different particle levels presents three stages, namely rapid decrease, slow decrease and stabilization. The oil driving pressures of various reservoirs and the differences of them decrease with the increase of temperature and obviously decrease with the increase of throat radius. According to the above experimental analysis, it is concluded that the deep shale oil of Fengcheng Formation in Mahu Sag has great potential for production under geological conditions.

This paper discusses the characteristics and formation mechanism of thin dolomite reservoirs in the lower submember of the second member of the Permian Maokou Formation (lower Mao 2 Member) in the Wusheng-Tongnan area of the Sichuan Basin, SW China, through comprehensive analysis of geological, geophysical and geochemical data. The reservoir rocks of the lower Mao 2 Member are dominated by porphyritic vuggy dolomite and calcareous dolomite or dolomitic limestone, which have typical karst characteristics of early diagenetic stage. The dolomites at the edge of the karst system and in the fillings have dissolved estuaries, and the dolomite breccia has micrite envelope and rim cement at the edge, indicating that dolomitization is earlier than the early diagenetic karstification. The shoal facies laminated dolomite is primarily formed by the seepage reflux dolomitization of moderate-salinity seawater. The key factors of reservoir formation are the bioclastic shoal deposition superimposed with seepgae reflux dolomitization and the karstification of early diagenetic stage, which are locally reformed by fractures and hydrothermal processes. The development of dolomite vuggy reservoir is closely related to the upward-shallowing sequence, and mainly occurs in the late highstand of the fourth-order cycle. Moreover, the size of dolomite is closely related to formation thickness, and it is concentrated in the formation thickness conversion area, followed by the thinner area. According to the understanding of insufficient accommodation space in the geomorphic highland and the migration of granular shoal to geomorphic lowland in the late highstand of the third-order cycle, it is proposed that the large-scale shoal-controlled dolomite reservoirs are distributed along structural highs and slopes, and the reservoir-forming model with shoal, dolomitization and karstification jointly controlled by the microgeomorphy and sea-level fluctuation in the sedimentary period is established. On this basis, the paleogeomorphology in the lower Mao 2 Member is restored using well-seismic data, and the reservoir distribution is predicted. The prediction results have been verified by the latest results of exploration wells and tests, which provide an important reference for the prediction of thin dolomite reservoirs under similar geological setting.

This study comprehensively uses various methods such as production dynamic analysis, fluid inclusion thermometry and carbon-oxygen isotopic compositions testing, based on outcrop, core, well-logging, 3D seismic, geochemistry experiment and production test data, to systematically explore the control mechanisms of structure and fluid on the scale, quality, effectiveness and connectivity of ultra-deep fault-controlled carbonate fractured-vuggy reservoirs in the Tarim Basin. The results show that reservoir scale is influenced by strike-slip fault scale, structural position, and mechanical stratigraphy. Larger faults tend to correspond to larger reservoir scales. The reservoir scale of contractional overlaps is larger than that of extensional overlaps, while pure strike-slip segments are small. The reservoir scale is enhanced at fault intersection, bend, and tip segments. Vertically, the heterogeneity of reservoir development is controlled by mechanical stratigraphy, with strata of higher brittleness indices being more conducive to the development of fractured-vuggy reservoirs. Multiple phases of strike-slip fault activity and fluid alterations contribute to fractured-vuggy reservoir effectiveness evolution and heterogeneity. Meteoric water activity during the Late Caledonian to Early Hercynian period was the primary phase of fractured-vuggy reservoir formation. Hydrothermal activity in the Late Hercynian period further intensified the heterogeneity of effective reservoir space distribution. The study also reveals that fractured-vuggy reservoir connectivity is influenced by strike-slip fault structural position and present in-situ stress field. The reservoir connectivity of extensional overlaps is larger than that of pure strike-slip segments, while contractional overlaps show worse reservoir connectivity. Additionally, fractured-vuggy reservoirs controlled by strike-slip faults that are nearly parallel to the present in-situ stress direction exhibit excellent connectivity. Overall, high-quality reservoirs are distributed at the fault intersection of extensional overlaps, the central zones of contractional overlaps, pinnate fault zones at intersection, bend, and tip segments of pure strike-slip segments. Vertically, they are concentrated in mechanical stratigraphy with high brittleness indices.

Considering the three typical phase-change related rock mechanics phenomena during drilling and production in oil and gas reservoirs, which include phase change of solid alkane-related mixtures upon heating, sand liquefaction induced by sudden pressure release of the over-pressured sand body, and formation collapse due to gasification of pore fillings from pressure reduction, this study first systematically analyzes the progress of theoretical understanding, experimental methods, and mathematical representation, then discusses the engineering application scenarios corresponding to the three phenomena and reveals the mechanical principles and application effectiveness. Based on these research efforts, the study further discusses the significant challenges, potential developmental trends, and research approaches that require urgent exploration. The findings disclose that various phase-related rock mechanics phenomena require specific experimental and mathematical methods that can produce multi-field coupling mechanical mechanisms, which will eventually instruct the control on resource exploitation, evaluation on disaster level, and analysis of formation stability. To meet the development needs of the principle, future research efforts should focus on mining more phase-change related rock mechanics phenomena during oil and gas resources exploitation, developing novel experimental equipment, and using techniques of artificial intelligence and digital twins to implement real-time simulation and dynamic visualization of phase-change related rock mechanics.

This paper investigates the macroscopic and microscopic characteristics of viscosity reduction and quality improvement of heavy oil in a supercritical water environment through laboratory experiments and testing. The effect of three reaction parameters, i.e. reaction temperature, reaction time and oil-water ratio, is analyzed on the product and their correlation with viscosity. The results show that the flow state of heavy oil is significantly improved with a viscosity reduction of 99.4% in average after the reaction in the supercritical water. Excessively high reaction temperature leads to a higher content of resins and asphaltenes, with significantly increasing production of coke. The optimal temperature ranges in 380-420 °C. Prolonged reaction time could continuously increase the yield of light oil, but it will also results in the growth of resins and asphaltenes, with the optimal reaction time of 150 min. Reducing the oil-water ratio helps improve the diffusion environment within the reaction system and reduce the content of resins and asphaltenes, but it will increase the cost of heavy oil treatment. An oil-water ratio of 1︰2 is considered as optimum to balance the quality improvement, viscosity reduction and reaction economics. The correlation of the three reaction parameters relative to the oil sample viscosity is ranked as temperature, time and oil-water ratio. Among the four fractions of heavy oil, the viscosity is dominated by asphaltene content, followed by aromatic content and less affected by resins and saturates contents.

Considering the interactions between fluid molecules and pore walls, variations in critical properties, capillary forces, and the influence of the adsorbed phase, this study investigates the phase behavior of the CO₂-shale oil within nanopores by utilizing a modified Peng-Robinson (PR) equation of state alongside a three-phase (gas-liquid-adsorbed) equilibrium calculation method. The results reveal that nano-confinement effects of the pores lead to a decrease in both critical temperature and critical pressure of fluids as pore size diminishes. Specifically, CO₂ acts to inhibit the reduction of the critical temperature of the system while promoting the decrease in critical pressure. Furthermore, an increase in the mole fraction of CO₂ causes the critical point of the system to shift leftward and reduces the area of the phase envelope. In the shale reservoirs of Block A in Gulong of the Daqing Oilfield, China, pronounced confinement effects are observed. At a pore diameter of 10 nm, reservoir fluids progressively exhibit characteristics typical of condensate gas reservoirs. Notably, the CO₂ content in liquid in 10 nm pores increases by 20.0% compared to that in 100 nm pores, while the CO₂ content in gas decreases by 10.8%. These findings indicate that confinement effects enhance CO₂ mass transfer within nanopores, thereby facilitating CO₂ sequestration and improving microscopic oil recovery.

Using the ultra-low permeability reservoirs in the L block of the Jiangsu oilfield as an example, a series of experiments, including slim tube displacement experiments of CO₂-oil system, injection capacity experiments, and high-temperature, high-pressure online nuclear magnetic resonance (NMR) displacement experiments, are conducted to reveal the oil/gas mass transfer pattern and oil production mechanisms during CO₂ flooding in ultra-low permeability reservoirs. The impacts of CO₂ storage pore range and miscibility on oil production and CO₂ storage characteristics during CO₂ flooding are clarified. The CO₂ flooding process is divided into three stages: oil displacement stage by CO₂, CO₂ breakthrough stage, CO₂ extraction stage. Crude oil expansion and viscosity reduction are the main mechanisms for improving recovery in the CO₂ displacement stage. After CO₂ breakthrough, the extraction of light components from the crude oil further enhances oil recovery. During CO₂ flooding, the contribution of crude oil in large pores to the enhanced recovery exceeds 46%, while crude oil in medium pores serves as a reserve for incremental recovery. After CO₂ breakthrough, a small portion of the crude oil is extracted and carried into nano-scale pores by CO₂, becoming residual oil that is hard to recover. As the miscibility increases, the CO₂ front moves more stably and sweeps a larger area, leading to increased CO₂ storage range and volume. The CO₂ full-storage stage contributes the most to the overall CO₂ storage volume. In the CO₂ escape stage, the storage mechanism involves partial in-situ storage of crude oil within the initial pore range and the CO₂ carrying crude oil into smaller pores to increase the volume of stored CO₂. In the CO₂ leakage stage, as crude oil is produced, a significant amount of CO₂ leaks out, causing a sharp decline in the storage efficiency.

Static adsorption and dynamic damage experiments were carried out on typical 8^# deep coal rock of the Carboniferous Benxi Formation in the Ordos Basin, NW China, to evaluate the adsorption capacity of hydroxypropyl guar gum and polyacrylamide as fracturing fluid thickeners on deep coal rock surface and the permeability damage caused by adsorption. The adsorption morphology of the thickener was quantitatively characterized by atomic force microscopy, and the main controlling factors of the thickener adsorption were analyzed. Meanwhile, the adsorption mechanism of the thickener was revealed by Zeta potential, Fourier infrared spectroscopy and X-ray photoelectron spectroscopy. The results show that the adsorption capacity of hydroxypropyl guar gum on deep coal surface is 3.86 mg/g, and the permeability of coal rock after adsorption decreases by 35.24%-37.01%. The adsorption capacity of polyacrylamide is 3.29 mg/g, and the permeability of coal rock after adsorption decreases by 14.31%-21.93%. The thickness of the thickener adsorption layer is positively correlated with the mass fraction of thickener and negatively correlated with temperature, and a decrease in pH will reduce the thickness of the hydroxypropyl guar gum adsorption layer and make the distribution frequency of the thickness of polyacrylamide adsorption layer more concentrated. Functional group condensation and intermolecular force are chemical and physical forces for adsorbing fracturing fluid thickener in deep coal rock. Optimization of thickener mass fraction, chemical modification of thickener molecular, oxidative thermal degradation of polymer and addition of desorption agent can reduce the potential damages on micro-nano pores and cracks in coal rock.

A flexible sidetracking stimulation technology of horizontal wells is formed to develop the lateral deep remaining oil and gas resources of the low-permeability mature oilfields. This technology first uses the flexible sidetracking tool to achieve low-cost sidetracking in the old wellbore, and then uses the hydraulic jet technology to induce multiple fractures to fracture. Finally, the bullhead fracturing of multi-cluster temporary plugging for the sidetracking hole is carried out by running the tubing string, to realize the efficient development of the remaining reserves among the wells. The flexible sidetracking stimulation technology involves flexible sidetracking horizontal wells drilling and sidetracking horizontal well fracturing. The flexible sidetracking horizontal well drilling includes three aspects: flexible drill pipe structure and material optimization, drilling technology, and sealed coring tool. The sidetracking horizontal well fracturing includes two aspects: fracturing scheme optimization, fracturing tools and implementation process optimization. The technology has been conducted several rounds of field tests in the Ansai Oilfield of Changqing, China. The results show that by changing well type and reducing row spacing of oil and water wells, the pressure displacement system can be well established to achieve effective pressure transmission and to achieve the purpose of increasing liquid production in low-yield and low-efficiency wells. It is verified that the flexible sidetracking stimulation technology can provide favorable support for accurately developing remaining reserves in low-permeability reservoirs.

To address the challenges associated with existing separated zone oil production technologies, such as incompatibility with pump inspection operations, short effective working life, and poor communication reliability, an innovative electromagnetic coupling intelligent zonal oil production technology has been proposed. The core and accessory tools have been developed and applied in field tests. This technology employs a pipe string structure incorporation a release sub, which separates the production and allocation pipe strings. When the two strings are docked downhole, electromagnetic coupling enables close-range wireless transmission of electrical power and signals between the strings, powering multiple downhole intelligent production allocators (IPAs) and enabling two-way communication. Core tools adapted to the complex working conditions downhole were developed, including downhole electricity & signal transmission equipment based on electromagnetic coupling (EST), IPAs, and ground communication controllers (GCCs). Accessory tools, including large-diameter release sub anchor and cable-crossing packers, have also been technically finalized. Field tests conducted on ten wells in Daqing Oilfield demonstrated that the downhole docking of the two strings was convenient and reliable, and the EST worked stably. Real-time monitoring of flow rate, pressure and temperature in separate layers and regulation of zonal fluid production were also achieved. This technology has enhanced reservoir understanding and achieved practical production results of increased oil output with reduced water cut.

In order to identify the development characteristics of fracture network in tight conglomerate reservoir of Mahu after hydraulic fracturing, a hydraulic fracturing test site was set up in the second and third members of Triassic Baikouquan Formation (T₁b₂ and T₁b₃) in Ma-131 well area, which learned from the successful experience of hydraulic fracturing test sites in North America (HFTS-1). Twelve horizontal wells and a high-angle coring well MaJ02 were drilled. The orientation, connection, propagation law and major controlling factors of hydraulic fractures were analyzed by comparing results of CT scans, imaging logs, direct observation of cores from Well MaJ02, and combined with tracer monitoring data. Results indicate that: (1) Two types of fractures have developed by hydraulic fracturing, i.e. tensile fractures and shear fractures. Tensile fractures are approximately parallel to the direction of the maximum horizontal principal stress, and propagate less than 50 m from perforation clusters. Shear fractures are distributed among tensile fractures and mainly in the strike-slip mode due to the induced stress field among tensile fractures, and some of them are in conjugated pairs. Overall, tensile fractures alternate with shear fractures, with shear fractures dominated and activated after tensile ones. (2) Tracer monitoring results indicate that communication between wells was prevalent in the early stage of production, and the static pressure in the fracture gradually decreased and the connectivity between wells reduced as production progressed. (3) Density of hydraulic fractures is mainly affected by the lithology and fracturing parameters, which is smaller in the mudstone than the conglomerate. Larger fracturing scale and smaller cluster spacing lead to a higher fracture density, which are important directions to improve the well productivity.

China has abundant resources of hot dry rocks. However, due to the fact that the evaluation methods for favorable areas are mainly qualitative, and the evaluation indicators and standards are inconsistent, which restrict the evaluation efficiency and exploration process of dry hot rocks. This paper is based on the understanding of the geologic features and genesis mechanisms of hot dry rocks in China and abroad. By integrating the main controlling factors of hot dry rock formation, and using index grading and quantification, the fuzzy hierarchical comprehensive method is applied to establish an evaluation system and standards for favorable areas of hot dry rocks. The evaluation system is based on four indicators: heat source, thermal channel, thermal reservoir and cap rock. It includes 11 evaluation parameters, including time of magmatic/volcanic activity, depth of molten mass or magma chamber, distribution of discordogenic faults, burial depth of thermal reservoir, cap rock type and thickness, surface thermal anomaly, heat flow, geothermal gradient, Moho depth, Curie depth, Earthquake magnitude and focal depth. Each parameter is divided into 3 levels. Applying this evaluation system to assess hot dry rock in central Inner Mongolia revealed that Class I favorable zones cover approximately 494 km², while Class II favorable zones span about 5.7×10⁴ km². The Jirgalangtu Sag and Honghaershute Sag in the Erlian Basin, along with Reshuitang Town in Keshiketeng Banner, Reshui Town in Ningcheng County, and Reshuitang Town in Aohan Banner of Chifeng City, are identified as Class I favorable zones for hot dry rock resources. These areas are characterized by high-temperature subsurface molten bodies or magma chambers serving as high-quality heat sources, shallow thermal reservoir depths, and overlying thick sedimentary rock layers acting as caprock. The establishment and application of the evaluation system for favorable areas of hot dry rock are expected to provide new approaches and scientific basis for guiding the practice of selecting hot dry rock areas in China.

Wells CXD1 and CX2 have uncovered high-concentration potassium-and lithium-containing brines and substantial layers of halite-type polyhalite potash deposits within the 4th and 5th members of the Triassic Jialingjiang Formation and the 1st Member of Leikoupo Formation (Jia 4 Member, Jia 5 Member, and Lei 1 Member) in the Puguang area, Sichuan Basin. These discoveries mark significant breakthroughs in the exploration of deep marine potassium and lithium resources within the Sichuan Basin. Utilizing the concept of “gas-potassium-lithium integrated exploration” and incorporating drilling, logging, seismic, and geochemical data, we have investigated the geological and enrichment conditions, as well as the metallogenic model of potassium-rich and lithium-rich brines and halite-type polyhalite. First, the sedimentary systems of gypsum-dolomite flats, salt lakes and evaporated flats were developed in Jia 4 Member, Jia 5 Member, and the 1st member of Leikoupo Formation (Lei 1 Member) in northeastern Sichuan Basin, forming three large-scale salt-gathering and potassium formation centers in Puguang, Tongnanba and Yuanba, and developing reservoirs with potassium-rich and lithium-rich brines, which are favorable for the deposition of potassium and lithium resources in both solid or liquid phases. Second, the soluble halite-type polyhalite has a large thickness and wide distribution, and the reservoir brine has a high content of K⁺ and Li⁺. A solid-liquid superimposed “three-story structure” (with the lower thin-layer of brine reservoir in lower part of Jia 4 Member and Jia 5 Member, middle layer of halite-type polyhalite potash depositS, upper layer of potassium-rich and lithium-rich brine reservoir in Lei 1 Member) is formed. Third, the ternary enrichment and mineralization patterns for potassium and lithium resources were determined. Vertical superposition of polyhalite and green bean rocks is the mineral material basis of potassium-lithium resources featuring “dual-source replenishment and proximal-source release”, with primary seawater and gypsum dehydration as the main sources of deep brines, while multi-stage tectonic modification is the key to the enrichment of halite-type polyhalite and potassium-lithium brines. Fourth, the ore-forming process has gone through four stages: salt-gathering and potassium-lithium accumulation period, initial water-rock reaction period, transformation and aggregation period, and enrichment and finalization period. During this process, the halite-type polyhalite layer in Jia 4 Member and Jia 5 Member is the main target for potassium solution mining, while the brine layer in Lei 1 Member is the focus of comprehensive potassium-lithium exploration and development.