Well Fengye 1 is the first shale gas risk exploration well deployed by Jiangsu Oilfield in the Huangui-Liuzhou karst cave development zone, aiming to obtain shale parameters of the Lugaizai Formation in the Fengshan Syncline and evaluate the regional shale gas exploration potential. The well penetrated exclusively Middle-Upper Paleozoic strata and faced multiple challenges including scarce data from adjacent wells, complex surface-subsurface structures, and significant drilling difficulties, specifically severe shallow lost circulation, poor formation drillability, wellbore instability and collapse, long-interval systematic coring, and ultra-long cementing sections. To achieve safe and efficient drilling, this study implemented a series of targeted technical measures: Pre-drilling detection using high-density electrical and wide-field electromagnetic methods to identify caves or fractured zones within 1 000 m depth around the well location, optimizing well placement and avoiding severe shallow lost circulation at the source. Based on established formation drillability profiles and real-time bit adaptability analysis, wear- and impact-resistant high-efficiency drill bits and coring tools were selected, significantly improving the rate of penetration (ROP) in each drilling phase. For lost circulation in the Maping Formation, after fully exposing the loss zone by drilling with water, a high-injection high-squeeze plugging technique was successfully applied to address severe loss. For collapse of hard-brittle sandstone and mudstone in the Huangjin Formation, a drilling fluid system with multi-grade particle size distribution and nano-micro sealing materials, combined with engineering measures such as dedicated reaming and viscous slurry sweeping, was used to promptly restore wellbore stability. To overcome coring difficulties such as hard and fractured lithology, high-angle fractures, and long open-hole sections, coring bits and barrels were optimized along with coring parameters, resulting in 220.08 m of core recovered with an average recovery rate of 97.36%. To mitigate cementing risks in the long interval, including potential fluid loss and "hourglass" wellbore geometry, cementing parameters were optimized based on caliper log analysis and loss zone identification. A combination of forward injection-reverse squeeze cementing technology and an elastic-flexible gas migration-resistant cement slurry system was employed, successfully cementing the 5 540 m section with excellent quality. Through the integrated application of these key technologies, Well Fengye 1 was completed efficiently and safely, with promising hydrocarbon shows encountered in the second member of the Lugaizai Formation. This well provides important technical reference and a practical model for subsequent shale gas exploration and development in this region.
The Lower Cambrian Qiongzhusi Formation shale is another marine shale series with great exploration potential in the Sichuan Basin after the Wufeng-Longmaxi Formation. Quartz is one of the most common and important minerals in marine shale, and its siliceous source and content have an important influence on organic matter enrichment and pore development. This paper takes the shale of Qiongzhusi Formation in Jingyan-Ziyang area as the object, and comprehensively uses X-ray diffraction, field emission scanning electron microscopy, main and trace element analysis and other test methods to carry out genetic classification and quantitative analysis of siliceous sources of shale quartz in the study area, and to explore the influence of quartz from different siliceous sources on reservoir quality. The results show that : (1) The main source of the Qiongzhusi Formation shale in the study area is from the Kangdian ancient land. The overall deposition and diagenesis process is weakly affected by the thermal fluid activity. It has experienced moderate chemical weathering. The paleoclimate humidity and paleo-ocean water body reducibility show an increasing trend from Jingyan to Ziyang, which makes the Qiongzhusi Formation shale reservoir in Ziyang area more enriched in organic matter and better reservoir performance than that in Jingyan area.(2) According to the quartz morphology, crystal size and cathodoluminescence intensity ( CL ), the shale quartz in the study area can be divided into : terrigenous detrital quartz, overgrowth quartz, bioclastic quartz and microcrystalline quartz. The siliceous is mainly derived from terrigenous input, biosilica evolution and clay mineral transformation. The quantitative results show that terrigenous input quartz accounts for 81%, bio-quartz accounts for 14%, and S-I quartz ( Smectite-to-Illitequartz ) accounts for 5%. The terrigenous input intensity is high. (3) There are significant differences in the influence of quartz from different siliceous sources on the shale reservoirs of Qiongzhusi Formation. Terrestrial clastic quartz dilutes organic matter and is not conducive to pore development ; bio-quartz provides support protection and storage space for organic matter, while enhancing the compressive strength of shale and protecting pores. S-I quartz has a dual effect on organic matter. The protection effect of S-I quartz in Qiongzhusi Formation in Jingyan area is dominant, and the destruction effect in Ziyang area is more significant. On the whole, S-I quartz fills the cemented pores and inhibits the development of pores. The research results aim to clarify the genetic mechanism of shale quartz in the Qiongzhusi Formation in the study area, reveal the influence of different genetic quartz on the reservoir, and provide geological basis for the identification of favorable intervals of shale reservoirs and the exploration and development of shale gas in this area.
The Member 2 of the Funing Formation continental shale oil in the Subei Basin exhibits promising exploration and development potential. Nevertheless, systematic understanding remains lacking regarding the genetic mechanism of microscale self-sealing in shale reservoirs and its controlling effect on differential enrichment of shale oil. Taking dark shales from the Member 2 of the Funing Formation in the Hai'an, Qintong and Gaoyou sags as the research target, this study integrates multiple experimental testing techniques including X-ray diffraction (XRD), high-pressure mercury intrusion, low-temperature nitrogen adsorption, scanning electron microscopy (SEM) and rock pyrolysis. Characteristic parameters such as shale mineral composition, microscopic pore structure, capillary force and adsorption force are systematically characterized to identify the microscale controlling factors of shale reservoir self-sealing and reveal differential genetic mechanisms of oil-bearing property and oil mobility between sweet intervals and sealing layers. The results indicate that the shales in the study area are dominated by mixed lithofacies shale, occurring in three forms: massive, bedded and laminated fabrics. Primary pore types comprise clay intercrystalline pores, clastic intergranular pores and carbonate dissolution pores. Pore sizes of sealing layers are predominantly distributed within 2-20 nm, featuring complex pore configurations and poor pore-throat connectivity. In contrast, sweet intervals have a dominant pore size range of 20-80 nm with markedly superior pore connectivity compared with sealing layers. Pore structure and pore type govern the intensity of capillary-driven self-sealing and adsorption-driven self-sealing in Member 2 Funing shales. The proportion and occurrence of clay intercrystalline pores, together with microcrystalline calcite infilling, jointly regulate pore-throat evolution and further determine the magnitude of capillary force and adsorption force. Variations in reservoir self-sealing capacity control differential enrichment of shale oil. Sweet intervals possess weak self-sealing capacity, characterized by high free hydrocarbon content, strong crude oil mobility, oil saturation across full pore size. Sealing layers feature strong self-sealing capacity; shale oil mainly accumulates less than 50 nm pores and mostly exists in adsorbed state with restricted mobility. The strong self-sealing capacity of sealing layers exerts twofold constraints: it inhibits intra-layer hydrocarbon migration and flow, and prevents hydrocarbon loss from sweet intervals into sealing layers. The synergistic effect of these two constraints ultimately establishes an intact in-situ self-sealing system within the shale succession.
Continental mixed shale reservoirs exhibit complex pore-fracture architectures and strong heterogeneity, which constitute one of the key geological factors restricting the optimal selection of shale oil “sweet spot” intervals and efficient development. To clarify reservoir-space types, the architecture of pore-fracture systems, and their main controlling factors in mixed shale, this study investigated the mixed shale from the Permian Fengcheng Formation in the Mahu Sag, Junggar Basin. Experimental techniques, including core observation, thin-section analysis, microscopic characterization, low-temperature N2 adsorption, and high-pressure mercury intrusion, were integrated to systematically characterize the reservoir space and analyze its controlling factors. The results showed that the reservoir space in the Fengcheng Formation was mainly classified into three types: inorganic pores, organic matter pores, and microfracture systems. The inorganic pores included intergranular pores, intragranular dissolution pores, and intercrystalline pores, among which intergranular pores were dominant and mainly occurred between felsic mineral grains. The microfractures were primarily bedding fractures and tectonic microfractures, with apertures predominantly in the 10-30 μm range, and they contributed significantly to pore-fracture connectivity and fluid seepage capacity in reservoirs. Full-pore-size characterization indicated a typical bimodal pore-size distribution in shale of the study area, corresponding to a micropore domain below 100 nm and a macropore domain above 2 000 nm. The average total pore volume of the reservoir was about 0.008 5 cm³/g. Reservoir performance varied significantly among lithofacies, generally following the order: felsic shale > mixed shale > clay-rich shale. Mineral composition and lamination architecture collectively controlled the pore-fracture system by affecting reservoir space through pore enhancement by dissolution, pore reduction by cementation, and fracture development promoted by brittleness. Dissolution of quartz and plagioclase generated abundant secondary pores, while intercrystalline pores associated with clay minerals contributed to micropore volume. Carbonate cementation reduced pore-throat connectivity but could facilitate fracture development under tectonic stress. Interbedded felsic and mixed lithofacies promoted the development of bedding fractures, and organic-inorganic complexes within clay-rich laminae enhanced pore-network connectivity. Overall, pore-fracture coupled development is a key mechanism governing the effectiveness of mixed shale reservoirs and heterogeneity in their reservoir performance. These findings provide an important basis for constructing evaluation schemes for mixed shale oil reservoirs and optimizing the selection of “sweet spot” intervals.
Deep tight sandstones in the second member of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin, contain abundant natural gas resources. However, the low reserve discovery rate, low reserve utilization rate, and difficulty in reserve upgrading have long been major challenges for exploration and development in the region. The unclear distribution patterns and genetic mechanisms of gas and water in both horizontal and vertical directions have hindered further understanding of gas reservoirs and research on drilling deployment. This study aims to solve the dilemma of gas reservoir evaluation caused by the complex distribution of gas and water, and effectively promote exploration and development deployment. Based on actual drilling, logging, test data, and analytical data for natural gas and cores, this study analyzed the characteristics of natural gas enrichment and production under different combinations of geological elements at macroscopic and microscopic scales, in horizontal and vertical dimensions, and from the perspectives of original gas reservoir states and actual drilling conditions. The differences in gas and water occurrence and electrical response in intervals with different degrees of fracture development were clarified, and the principles and methods for identifying gas and water in tight fractured reservoirs under wellbore conditions were summarized. The results showed that: (1) macroscopically, the spatiotemporal coupling of the hydrocarbon source-reservoir-carrier bed controlled the vertical and horizontal distribution of gas and water, with the scale and formation stages of faults being key factors affecting gas and water distribution. (2) At the microscopic level, small-scale fractures and microfractures controlled the charging behavior of natural gas. High-maturity gas was difficult to migrate over long vertical and horizontal distances in matrix reservoirs. Fracture-developed intervals had significantly higher gas saturation and natural gas maturity than adjacent matrix intervals. (3) Under actual drilling conditions, the deep invasion of mud filtrate significantly reduced the resistivity distinguishability between gas-bearing and water-bearing layers in the fracture-developed intervals, which were ideal target areas for gas-bearing identification. The methane-to-ethane ratio φ(C1)/φ(C2), a key gas logging parameter, was used to characterize the rhythmic variation characteristics of natural gas maturity in intervals with different degrees of fracture development, effectively improving the gas-water identification ability of tight reservoirs. (4) The results of single-well gas-water identification showed that in early fault-controlled reservoir areas, the height of gas columns was usually less than 100 m, and the planar distribution radius of fault-fracture carrier beds was small. In contrast, in late fault-controlled reservoir areas, the height of gas columns and the planar distribution radius of fault-fracture carrier beds were usually larger and related to the size of the fault. Under the guidance of the fluid identification methods and gas-water distribution patterns mentioned above, drilling deployment was carried out, and general principles for designing drilling trajectories and selecting test layers for target layers were established. Multiple new drilling wells achieved favorable oil and gas results, which strongly supported the high-quality exploration and development of deep tight sandstone in the second member of the Xujiahe Formation in the Western Sichuan Depression, Sichuan Basin.
