For many years, the exploration of natural gas in the large structural belts of the northern Qaidam Basin has yielded unsatisfactory results, which may be related to the traditional interpretation of deep-seated paleo-anticlinal traps based on the dual-layer structural model. Through seismic data interpretation and structural analysis, it is concluded that the dominant structural style of this area is mainly of synsedimentary compressional strike-slip structures that developed in the late Himalayan period. Strongly deformed structures occur as a ruptured anticlines with faults extending to the surface, resulting in low-abundance traps of underfilled gas accumulations. In contrast, the gentle anticline of Chahan, which developed as a synsedimentary overlying anticline over uplifted fault blocks associated with deep compressional strike-slip movement, exhibits more favorable conditions for hydrocarbon accumulation. Because deformation related with strike-slip belt is primarily concentrated along fault zones, the intervening sags generally experience relatively weak deformation, which is conducive to the preservation of gas reservoirs and therefore represents favorable targets for gas exploration as long as there is a gas source rocks. The Pingdong Sag, located between the Altun, Jianshan, and Eboliang structural belts, experienced gentle deformation during the Cenozoic and exhibits relatively complete distribution of three Mesozoic–Cenozoic tectonic layers, containing all geologic elements of a gas system. The deep-buried Jurassic source rocks within the sag are characterized by larger thickness and stable distribution and are currently in the stage of gas generation, suggesting that major gas accumulation occurred during the late Himalayan period. The fault-block structures developed in the lower Cenozoic tectonic layer provided effective migration and accumulation system. The lower Youshashan Formation (N21) delta front sandstone bodies and overlying mudstone intervals form favorable reservoir-caprock assemblages, while the lacustrine mudstones and evaporites in the upper tectonic layers (N22, N23, Q) offer an effective regional sealing conditions for gas preservation. The analysis suggests that the Chahan anticline, located above the source-rock and developed contemporaneously with major gas-generation phase, has the potential to host a large gas field. Furthermore, subtle traps beneath the regional sealing strata, including low-amplitude anticlines, fault-block traps, lithological traps on tectonic setting, and fault–sandstone combination traps within the sub-sags of the Pingdong Sag, constitute favorable exploration targets for natural gas. This study also has reference significance for natural gas exploration in regions characterized by tectonic settings similar to those of the Qaidam Basin.
Optimal well spacing is crucial for maximizing single-well productivity and efficiently utilizing reserves, making it a core indicator for evaluating development effectiveness. Due to the influence of natural fractures and the production sequence, the annual well opening pressure and inter-well interference in the Weirong Gas Field have led to an intensifying year-on-year decline, which have seriously affected both production and construction outcomes. To reduce inter well interference and improve productivity and construction efficiency, this study analyzes the interference mechanisms between wells. The results show that the main causes of interference are natural fractures and older well energy depletion. Based on these insights, a numerical simulation method was used to quantitatively evaluate the impact of varying well spacing, degrees of fracture hit and cumulative gas production from older wells on the Estimated Ultimate Recovery (EUR) of new wells. Consequently, a targeted and differentiated well spacing optimization design method was developed. The results show that: (1) The smaller the well spacing and the higher the degree of fracture hit, the greater the decrease on the EUR of new wells, with impact degrees of 7.1%-15.1%; (2) The smaller the well spacing and the higher the cumulative gas production from older wells, the greater the negative impact on the EUR of new wells, ranging from 8.1% to 28.3%; (3) In areas with well-developed natural fractures, a recommended well spacing of 350-450 m is suggested based on the fracture hit degree; (4) Near older wells, where energy depletion is prominent, a well spacing of 400-500 m is recommended. Following the application of well spacing optimization, the average well opening pressure increased by 9.3 MPa, and the EUR improved by 22.8%, demonstrating a favorable application effect and providing reference for well pattern arrangement in similar shale gas reservoirs.
The Ordovician ultra-deep carbonate reservoirs in the Tarim Basin are rich in oil and gas resources. However, due to the influence of multiple periods of tectonic activity, their distribution shows strong heterogeneity. In regions characterized by fault-controlled fractures and caves, traditional reservoir quality evaluation methods based on physical property parameters are subject to considerable uncertainty. In contrast, methods incorporating geomechanical parameters show notable advantages. In this study, geomechanical parameters—such as present-day in-situ stress, elastic modulus, and natural fracture density—were quantitatively characterized. A geological model of the carbonate fracture-cavity system was established, and a reservoir quality evaluation factor was defined and calculated to enable a quantitative evaluation of ultra-deep carbonate reservoir quality. The results indicate that: (1) In fault-controlled fracture-cavity ultra-deep carbonate reservoirs, the spatial distribution of geomechanical parameters has strong heterogeneity and significantly affected by fault structure. This distribution is segmented along the fault extension direction. Both the elastic modulus and natural fracture density indicate elevated values near fault zones, while present-day in-situ stresses are relatively lower in these areas. (2) Reservoir geomechanical parameters are strongly responsive to the structural and geological characteristics of fault-controlled fracture-cavity carbonate oil and gas reservoirs. The proposed evaluation methods are effective in evaluating reservoir quality and provide a valuable geological reference and support for the efficient exploration and profitable development of fault-controlled fracture-cavity ultra-deep carbonate reservoirs.
The Ordos Basin is the largest natural gas producing region in China. Recent discoveries of two helium-rich natural gas fields (Dongsheng and Qingyang) shows promising helium resource potential. Sulige Gas Field, the largest natural gas field in China, was analyzed to evaluate its helium resource potential. Comprehensive geochemical analyses were conducted, examining natural gas components, alkane gases, carbon isotopic signatures of carbon dioxide, helium concentrations, and helium isotopic ratios within the gas field. Preliminarily studies identified the geochemical characteristics of natural gas and helium in the Paleozoic strata of Sulige Gas Field, and explored the main controlling factors of helium reservoir formation. The results show that the composition of natural gas in the Upper Paleozoic is obviously different. Specifically, Upper Paleozoic natural gas exhibited typical wet gas at the mature stage and dry gas at the over-mature stage, while Lower Paleozoic natural gas is mainly dry gas with partial contribution of wet gas. The Upper Paleozoic is dominated by thermogenic natural gas, predominantly middle-late humic gas (coal-derived) originating from Carboniferous and Permian coal measure source rocks. In contrast, the Lower Paleozoic is dominated by late sapropelic dry gas and oil cracking gas. The helium concentrations in Paleozoic natural gas is higher than in conventional natural gas (0.03%), which belongs to middle helium gas, and the Upper Paleozoic is exceeding those of the Lower Paleozoic. The helium accumulation in the Sulige Gas Field is influenced by the ancient and modern structural location, the high helium generation intensity and relatively low hydrocarbon generation potential of helium source rocks (such as U–Th-rich basement granite and granite gneiss), the development of basement faults, and the complex gas–water relationship, which is favorable for the helium to dissolve out of the water and enter into the natural gas reservoirs.
Different helium source rocks exhibit varying characteristics, including differences in the content and occurrence states of precursor elements such as uranium (U) and thorium (Th). In sedimentary rocks, U and Th mainly exist in adsorbed and (or) complexed states of organic matter and clay minerals. The primary migration of helium generated in sediments is liable to occur due to the lack of mineral crystal restraint. Hence, source rocks and reservoir rocks in gas pools act as the primary effective helium source rocks in sediments. In contrast, other sedimentary rocks are less effective as helium sources due to the fact that high porosity results in prolonged helium saturation, thereby restraining the desolubilization and secondary migration of helium. In igneous rocks, isomorphous U and Th are mainly enriched in silicate and phosphate minerals. Temperature is the main controlling factor affecting their primary migration. Granite, characterized by low porosity and limited helium solubility, can experience large-scale release helium under conditions of tectonic uplift and abnormally high temperatures, acting as an effective helium source rock for helium-rich natural gases. Various forms of U and Th can exist in metamorphic rocks, which have higher porosity and higher soluble helium contents than granite, but this result in greater difficulty in helium release. Although the direct source rocks and reservoirs of natural gas reservoirs are effective helium source rocks, it is difficult to form He-rich natural gas due to the influence of hydrocarbon dilution. Sufficient He supply from basin basement or mantle-derived sources is a key condition for natural gas reservoirs to be rich in He.
