Journal of Natural Gas Geoscience最新文献

Gold tube thermal simulation experiments represent a pivotal tool in exploring hydrocarbon generation kinetics in hydrocarbon source rocks. Compared to other reaction systems, the reaction environment and the pyrolysis product composition within the gold tube display a greater resemblance to actual geological conditions, especially for coal-based hydrocarbon rocks with poor hydrocarbon removal capacity. The kerogen is in close contact with various pyrolysis products and reacts with each other in the gold tube. Researchers have carried out extensive research and application in hydrocarbon generation kinetics based on gold tubes in recent years. But a systematic and comprehensive summary of these studies is lacking. This paper provides a review of the kinetic study based on golden tubes in recent years from the perspectives of research objects, influencing factors, applications and problems. The main targets of hydrocarbon generation kinetics based on gold tubes include CH₄, C_1-5, C₈₊ and so on. Elucidating the kinetics of diverse pyrolysis products aids comprehension of the mechanism of organic matter pyrolysis. Reaction condition, minerals and organic structure all influence hydrocarbon production kinetics. Clarifying the effects of these influencing factors is of great importance in understanding the pyrolysis mechanism of hydrocarbon source rocks and pyrolysis research in the domain of hydrocarbons. Golden tube-based kinetic studies of hydrocarbon production have good potential application, not only in determining the hydrocarbon generation history of hydrocarbons in the study area, but also in studying the genesis, origin, and reservoir formation mode of natural gas. This paper also summarizes some problems and solutions of the gold tube hydrocarbon generation kinetics, such as the inhomogeneity of the samples, the difference between the gold tube system and natural conditions, and the determination of the time point of oil secondary cracking. Continuous optimization of the solution enhances the authenticity of the golden tube simulation experiment. This review aims to offer a theoretical foundation and research suggestions for investigating pyrolysis kinetics of hydrocarbon source rocks and hydrocarbons based on golden tubes.

The Well Mitan-1 has achieved a major breakthrough in the exploration of Ordovician subsalt natural gas in the mid-eastern Ordos Basin, demonstrating a high-yield industrial gas flow in fourth member of the Majiagou Formation of Ordovician (O₁m₄). Despite this success, there are ongoing disputes regarding the origin of the natural gas found in Well Mitan-1. Measured results show that the natural gas in Well Mitan-1 is mainly composed of alkane gas (95.18 %). The gas drying coefficient (C₁/C_1-5) is measured at 0.947, and the H₂S content is 3.49 %, with a small amount of N₂ and CO₂ in the non-hydrocarbon gas. The carbon isotopic compositions of methane, ethane, and propane in the natural gas are −45.5 ‰, −26.4 ‰, and −24.3 ‰, respectively. Based on the regional geological background, the characteristics of potential source rocks and the geochemical characteristics of natural gas, it is considered that the natural gas in Well Mitan-1 is self-generated and self-accumulated oil-associated gas in Ordovician subsalt carbonate rocks. However, certain geochemical anomalies, such as the lighter methane carbon isotope value (δ¹³C₁) and coal-type gas characteristics in ethane carbon isotope (δ¹³C₂), raise questions. Further insights from thermal simulation experiments on hydrocarbon generation and the analysis of residual gas in rocks suggest a close relationship between the special geochemical characteristics of Well Mitan-1 and the presence of gypsum rocks. The ubiquitous gypsum rock serves a dual purpose: acting as an effective caprock, facilitating the retention of early-generated natural gas, and promoting the generation of heavy hydrocarbon gases (C₂₊) and H₂S. The relatively low H₂S content (less than 5 %) and higher C₂₊ content indicate that thermochemical sulfate reduction (TSR), if present, is not strong enough to significantly impact methane. The δ¹³C₂ is identified as a potentially sensitive parameter for identifying TSR.

Helium, a critical rare strategic resource primarily sourced from natural gas, is currently a subject of intense research regarding its enrichment processes within gas reservoirs. Investigating the enrichment of helium is urgent and vital for advancing helium exploration. This study involved the collection of natural gas samples from the Qaidam, Sichuan, and Junggar basins for helium and nitrogen content testing and analysis. The findings were combined with studies on natural gas fractions and helium content in local and international major helium-rich fields. The investigation revealed a strong correlation between helium content and nitrogen presence in helium-rich fields, a phenomenon that also extends to some helium-poor fields. Accordingly, this study proposes a coupling relationship between helium and nitrogen, suggesting that both elements are simultaneously enriched in natural gas. Furthermore, both are associated with groundwater and may share a common origin in source rocks. This proposed coupling relationship holds the potential to unveil the mystery of helium enrichment, offering a new perspective for the exploration of helium-rich resources and providing a foundational framework for helium enrichment theory.

Based on core data, physical properties, well logging, gas testing, composition, and helium distribution from 13 newly drilled wells, in combination with regional tectonic evolution, depositional background, and typical gas reservoir profiles, helium-rich gas reservoirs geology characteristics and main controlling factors have been explored. The results show that three gas reservoirs formed from bottom to top, i.e., granite and metamorphite fractured reservoir in the basement, tight sandstone structural reservoirs in the Devonian, and huge continuous carbonate reservoirs in the Lower Carboniferous. Fractures developed on structural points control high-production, and gas is prominently displayed in low structural areas. The dry gas exhibits richness in helium, with decreasing helium content from the basement to the Carboniferous. The pre-Devonian large-scale granite and metamorphite basement serve as the primary helium source, while the high-gamma sandstones of the Devonian and the Carboniferous act as secondary sources. Fractures play a dual role, being filled up and conducting in two ways: gas from the Carboniferous source rocks migrates downward, and helium migrate upward. Thick interbedded gypsum-tight limestone on top of the Lower Carboniferous act as the regional caprock, effectively preserving the helium-rich gas reservoirs.

Guizhou Province of China is rich in shale gas resources. In recent years, important progress has been made in the exploration and development of shale gas in the Upper Ordovician Wufeng Formation-Lower Silurian Longmaxi Formation in Zheng'an block in northern Guizhou, adjacent to Sichuan Basin. Due to the complex geological conditions and fragile ecological environment in the shale gas distribution area, serious environmental pollution risks may exist in shale gas exploitation. Therefore, this paper conducted element, hydrogen and oxygen isotope analyses for shale gas fracturing flowback/produced water of Well AY7-4 in Zheng'an block. The results showed that the contents of K, Na, Ca, Mg and $N{H}_4^{+}$ in the flowback/produced water of Well AY7-4 were very high, with an average of 118 mg/L, 7616 mg/L, 266 mg/L, 47 mg/L and 76 mg/L, respectively. The content of Na, Ca and Mg is similar to that of shale gas flowback/produced water in Weiyuan, but lower than that in Changning and Fuling. $N{H}_4^{+}$ content was similar to that in Changning, but much higher than that in Weiyuan. The average Cl content was 11605 mg/L, which was similar to that in Weiyuan, but lower than that in Changning and Fuling. The average Br content is 48 mg/L, slightly lower than that of Weiyuan, and about half of that of Changning and Fuling. Correspondingly, the Br/Cl value of Well AY7-4 is the lowest, reflecting its relatively low Br content. The average content of Li, B and Sr is 17 mg/L, 10 mg/L and 45 mg/L, respectively, which is similar to that of the Weiyuan, Changning and Fuling shale gas fields. The distribution model of Li and Sr is similar to that of Cl, Br and Na, but the B content and B/Cl value of Well AY7-4 are the lowest. The linear relationship between Br and Cl contents and between δD and δ¹⁸O of flowback/produced water of Well AY7-4, freshwater used for hydraulic fracturing and hydraulic fracturing injected fluid indicates that flowback/produced water of Well AY7-4 is mainly the mixed product between low salinity injected fracturing fluid and high salinity brine retained in shale formation. The hydrogen and oxygen isotopic compositions gradually become heavier over time, indicating that the proportion of high salt end formation brine in flowback/produced water is increasing. The contents of Cl, Br, Na and $N{H}_4^{+}$ in the flowback/produced water of Well AY7-4 are far higher than the allowable discharge value, which is a potential environmental pollution risk and cannot be discharged directly.

The PetroChina Changqing Oilfield Company has successfully achieved large-scale economical development of continental low-pressure freshwater lake interlayer shale oil in the Ordos Basin, China, targeting the gravity-flow sandstone thin interlayers in the organically rich mud shale formation of the seventh member of Yanchang Formation (Chang 7 Member) of Triassic,. Their significant discovery of the 1-billion-ton-level Qingcheng shale oil field, with a proven reserve of 1.052 × 10⁹ t, has marked the establishment of China's first million-ton shale oil development zone. However, the extensive growth in production and construction has brought attention to notable challenges, including geological variances, low initial production, rapid decline, low recovery rates, and high development costs. Based on extensive field experience, this paper identifies several technological issues in shale oil development and offers comprehensive recommendations through systematic analysis. The encounter rate of horizontal shale oil wells, crucial for enhancing individual well productivity, can be improved both vertically and horizontally by prioritizing the extension direction of high-quality reservoirs during the deployment of horizontal wells. The contribution of fracturing fluid elasticity to the recovery rate is relatively low. Reservoir modification should not overemphasize large sand volume, fluid volume, or discharge. Additionally, optimizing parameters such as well spacing, vertical interlayer distribution, and fracture development is essential for maximizing the efficiency of fracturing scale, operation discharge, and other parameters. Variability in hydrocarbon source rock quality and the strength of diagenesis significantly impact oil saturation in sand bodies, affecting the selection of favorable areas and the distribution of high-quality reservoirs. Furthermore, the utilization of pre-fracturing with CO₂ proves to be an effective approach in reducing viscosity and increasing the ultimate recovery rate. To ensure the efficient development of shale oil in the Changqing Oilfield, this paper emphasizes the necessity of deepening integrated geological studies, clarifying the main controlling factors of shale oil heterogeneous accumulation, and meticulously depicting three-dimensional sweet spots while exploring more effective development methodologies.

Studies focusing on the fault system in the Jurassic strata of the Sichuan Basin have been limited, restricting the understanding of the hydrocarbon accumulation mode of the Shaximiao Formation and the expansion of exploration. Through interpretation and coherent slice analysis of extensive seismic data, we have newly discovered that normal faults are widely developed in the northern central Sichuan Basin in the Jurassic strata. These faults mainly extend from the Lower to Upper Jurassic strata and are characterized by the continuous arrangement of NEE-trending small faults in the plane, with a few NNE-trending and NNW-trending faults also present. The distribution of Jurassic fault combinations varies within the basin, with normal faults mainly distributed in the low uplift areas of central Sichuan and the north of central Sichuan. Geochemical data comparisons indicate that these normal faults serve as conduits between the Jurassic source rocks and the Shaximiao Formation reservoir in these areas. Furthermore, the newly discovered normal faults are superimposed with the middle and lower Jurassic source rocks in the northern central Sichuan Basin, suggesting the formation of a new hydrocarbon accumulation model involving hydrocarbon generation from the middle and lower Jurassic, facilitated by communication through normal faults. Notably, one of the promising directions for exploration lies in the multi-stage channel superimposed development zone near these normal faults.

The evaluation of remaining reserves is crucial for assessing the developmental effect and further enhancing the recovery of a gas field. In this research, with the Changning shale gas field in the southern Sichuan Basin as the center of study, a comprehensive analysis was conducted on reservoir distribution, remaining reserves, and strategies to enhance recovery through the utilization of diverse methodologies, including organic geochemical testing, triaxial rock mechanics experiments, and numerical simulations. The results show that, in the study area, the recovery percentage of the well-controlled reserves ranges from 45% to 70%, with the average remaining reserves of wells falling within the (50–150) × 10⁶ m³ range, alongside the potential for additional development in specific local areas. The Changning shale gas field exhibits three distinct types of undeveloped reserves, identified in areas where no wells have been drilled, inadequately fractured zones, and vertically undeveloped areas, respectively. In the areas where the average remaining reserves of wells are exceeding 100 × 10⁶ m³, wells for repeated fracturing are selected depending on the coupling of geological, engineering, and development. In the case of well infilling, areas characterized by developed reticular fractures and existing well spacing >500 m are prioritized, taking into account the surface wellsite conditions. Through an extensive analysis, which include reservoir assessments, rock mechanics evaluations, and numerical modeling, sublayer⑤ is identified as the optimal target in the upper gas interval, with a vertical distance of more than 20 m from sublayer① in the lower gas interval. Zones with well-developed reticular natural fractures, a pressure coefficient >1.2, and a continuous thickness of Class I reservoirs in the upper gas interval >10 m, are selected for staggered tridimensional development with an expected increase in the platform-level recovery percent by 30%. These findings can provide valuable references and guidance for the deployment of well patterns in shale gas blocks.

The Bozi-Dabei area in the Kuqa Depression host high-quality reservoirs in the Bashijiqike Formation and Baxigai Formation sandstones of the Lower Cretaceous, in which reservoirs yield significant industrial gas flow despite being situated at a considerable burial depth of 8200 m. The geological history of the target formation involves multiple phases of tectonic movements, resulting in the development of multi-genetic fractures that enhance the reservoir's storage and seepage capacity. Based on the results of the drilling core, field profile survey, imaging logging, and experimental analysis, this study presents an analysis of fractures in the Lower Cretaceous dense sandstone reservoir of the Bozi-Dabei area, andclarifies the characteristics and controlling factors of the multi-genesis and multi-period fractures. Additionally, it proposes an effective fracture development model that accounts for geo-stress control. In the Bozi-Dabei area, the prevailing high extrusion stress environment has led to the development of predominantly regional tectonic fractures and fault-related fractures, with relatively gentle deformation-related fractures. The results of a combination of multi-attribute data determination techniques, including fracture filling, inter-cutting relationship, fracture filling isotope, inclusions, and cathode luminescence tests, this study reveals that the reservoir fractures have experienced three major periods of tectonic movement. The regional tectonic fracture development is mainly controlled by stratigraphic lithology and thickness, while the proximity influences fault co-derived fractures to the fault and the relative positions of the upper and lower plates of the fault. The shift in the direction of the late horizontal maximum principal stress leads to the opening or closing of early fractures under different conditions in the Bozi-Dabei area, consequently affecting the degree of fracture opening and effectiveness. Notably, when the horizontal maximum principal stress is deflected to intersect with early fractures at a smaller angle or even superimpose, the fracture effectiveness of the related group system in the deflection direction improves, resulting in an overall coordination. The distribution characteristics of the fracture system in this highly productive reservoir are the result of dominant configurations from multi-phases of geological activities.

Multi-layer commingled production is the main feature of gas well development in Sulige tight sandstone gas reservoir, Ordos Basin. Identifying potential interference between layers and devising methods for their characterization are crucial considerations for optimizing the development of gas reservoirs. To address these issues, we designed a physical simulation experiment process and interlayer commingled mining schemes, implementing various interlayer combination modes. The results show that a common occurrence in the process of multi-layer commingled production of tight gas and water layers, whether it involves gas layers production alone or simultaneous production of gas and water layers. This phenomenon involves the crossflow of gas and water between layers, resulting in interlayer interference and a subsequent reduction in gas reservoir recovery. Based on these observations, the concept of an interlayer interference index in multi-layer commingled production in tight sandstone gas reservoirs is proposed. The interference index model is obtained by fitting the multiple linear regression method, showcasing its correlation with the physical properties of the reservoir. High water saturation and a significant permeability ratio of the water layer to the gas layer (exceeding the critical value of 1) can result in the early occurrence of interlayer interference and yield a higher interference index. Furthermore, based on the interference index model, a novel method for productivity evaluation of gas wells in tight gas reservoirs is established. The calculations demonstrate that the interference index curve effectively characterizes the interlayer interference performance of gas wells. The productivity and production performance predictions derived from this model align closely with historical production data, affirming the model's effectiveness and accuracy. Therefore, the interference index model emerges as a valuable tool for predicting the productivity and production performance of gas wells in Sulige tight sandstone gas reservoirs. The research results have important theoretical guidance and practical significance for the efficient development of Sulige tight sandstone gas reservoirs.