Search Results (25)

Huhehu Sag is a sag with high exploration degree in Hailar Basin. With large sedimentary thickness, complete stratigraphic development and excellent oil generation conditions, it is the main oil- and gas-producing sag in Hailar Basin. The primary source rocks are the Nantun Formation, with the Tongbomiao and Damoguaihe Formations as secondary sources. Hydrocarbon accumulation periods in the sag were comprehensively analyzed using methodologies including source rock hydrocarbon generation-expulsion history, authigenic illite dating of reservoirs, and fluid inclusion homogenization temperature analysis. Results reveal two major accumulation stages: Stage 1 (125–90 Ma), corresponding to the depositional period of the Yimin Formation, represented the peak paleo-geothermal regime and the primary hydrocarbon accumulation phase. Intensive hydrocarbon generation and expulsion, coupled with robust migration dynamics, facilitated large-scale oil and gas pooling. Stage 2(65 Ma-now), from the deposition of Qingyuangang Formation to the present, uplift and denudation reduce the burial depth of source rocks, the hydrocarbon generation intensity is weakened. This phase involved secondary adjustments of pre-existing reservoirs and continued charging of newly generated hydrocarbons. The Huhehu Sag is a typical half-graben structure. Fault-block and fault-lithologic reservoirs dominate, distributed zonally along gentle and steep slopes. Lithologic reservoirs primarily occur near or within the central hydrocarbon-generating sub-sags. The most favorable hydrocarbon accumulation zones are located in the sub-sag centers and adjacent areas with high-quality reservoirs. Full article

The Qiongdongnan Basin constitutes a sedimentary basin characterized by elevated temperatures, significant overpressures, and abundant hydrocarbons. Investigations within this basin have identified hydrothermal fluid movements linked to overpressure conditions, comprising two vertically separated overpressured intervals. The shallow overpressure compartment is principally caused by a combination of undercompaction and clay diagenesis. In contrast, the deeper high-pressure compartment results from hydrocarbon gas generation. Numerical pressure modeling indicates late-stage (post-5 Ma) development of significant overpressure within the deep compartment. It is proposed that accelerated subsidence in the Pliocene-Quaternary initiated substantial gas generation, thereby promoting the formation of the deep overpressured system. Multiple organic maturation parameters, combined with fluid inclusion microthermometry, reveal a thermal anomaly adjacent to the upper boundary of the deep overpressured zone. This anomaly indicates vertical transport of hydrothermal fluids ascending from the underlying high-pressure zone. Laser Raman spectroscopy confirms the presence of both hydrocarbons and carbon dioxide within these migrating fluids. Integration of fluid inclusion thermometry with burial history modeling constrains the timing of hydrocarbon-carrying fluid charge to the interval from 4.2 Ma onward, synchronous with modeled peak gas generation and a phase of pronounced overpressure buildup. We propose that upon exceeding the fracture gradient threshold, fluid pressure triggered upward migration of deeply sourced, hydrocarbon-enriched fluids through hydrofracturing pathways. This process led to localized dissolution and fracturing near the top of the deep overpressured system, while simultaneously facilitating significant hydrocarbon accumulation and forming preferential accumulation zones. These findings provide critical insights into petroleum exploration in overpressured sedimentary basins. Full article

The Pinghu Oil and Gas Field in the East China Sea Shelf Basin represents a significant offshore hydrocarbon-producing region in East Asia. However, the Paleogene hydrocarbon system in the Pinghu Oil and Gas Field is complex, and the fluid properties, charging stages, and hydrocarbon accumulation process are still unclear. A comprehensive integrated analysis of the hydrocarbon accumulation characteristics, fluid properties, temperature pressure regimes, primary hydrocarbon sources and origins (genesis), charging stages, preservation conditions, and evolutionary history of hydrocarbon accumulation have been studied by utilizing a series of well data, oil and gas geochemical parameters, carbon isotope, and fluid inclusion analyses. Hydrocarbon charging in the Huagang Formation experienced one stage, and the crude oil is characterized as light and conventional, exhibiting low density and viscosity, a low pour point, and low contents of wax, resin, and sulfur. In contrast, the reservoir of the overpressured Pinghu Formation experienced a two-stage hydrocarbon charging process (oil filling and gas filling), exhibiting higher density, viscosity, and wax content compared to the Huagang Formation. The hydrocarbon charging and evolution process of the Pinghu Formation and Huagang Formation in the Pinghu Oil and Gas Field can be summarized in three different stages, including the oil filling period (10–5 Ma), gas filling period (5–2 Ma), and oil and gas adjustment period. The Pinghu Oil and Gas Field, especially in the lower Pinghu Slope Belt (Fangheting Structure), has good potential for further exploration. Full article

To elucidate the mechanisms governing hydrocarbon accumulation and phase evolution in the deep–ultradeep reservoirs of the Mo-Yong area, this study integrated 2D basin modeling and multi-component phase state simulation techniques, investigating the differences in maturity and hydrocarbon generation history between the Fengcheng Formation (P₁f) and the Lower Wuerhe Formation (P₂w) source rocks, as well as their coupling relationship with fault activity in controlling hydrocarbon migration, accumulation, and phase evolution. The results indicate that the P₁f and P₂w in the Mo-Yong area source rocks differ in thermal maturity and hydrocarbon generation evolution. The dual-source charging from both the P₁f and P₂w significantly enhances hydrocarbon accumulation number, volume, and saturation. The temporal-spatial coupling between peak hydrocarbon generation and multi-stage fault reactivation not only facilitates extra-source accumulation but also drives condensate reservoir formation through gas-oil ratio elevation and light-component enrichment. Based on these results, a model of hydrocarbon accumulation and phase evolution of deep reservoirs was proposed. The model elucidates the fundamental geological principle that source-fault spatiotemporal coupling controls hydrocarbon enrichment degree, while phase differentiation determines reservoir fluid types. Full article

Clarifying the phase evolution history of hydrocarbon fluids helps formulate exploration and development strategies. The discovery of the Xinguang Gas Field marks a significant breakthrough in the Western Junggar Basin. However, the phase evolution history of this gas field remains unclear, which hinders the formulation of subsequent exploration strategies. This study employs a comprehensive approach, combining organic geochemistry, fluid inclusions, basin modeling, and PVT testing and simulation, to investigate the characteristics and phase behavior of deep-seated hydrocarbon fluids in this gas field. It also examines the charging history, compositional evolution, and temperature and pressure histories of the reservoir, thereby clarifying the phase transition process of hydrocarbon fluids in the Xinguang Gas Field. This study finds that the deep-seated reservoir fluids in the Jiamuhe Formation (Fm.) of the Xinguang Gas Field exhibit low densities of 0.77 to 0.83 g/cm³, high gas-to-oil ratios (GORs) of 1014.41 to 13,054.77 m³/m³, high methane contents of 91.16% to 92.74%, and retrograde condensation characteristics. Additionally, the reservoir temperature and pressure exceed the critical point and the saturation pressure at reservoir temperature, indicating a supercritical condensate gas phase. The present condensate gas in the Xinguang Gas Field is a mixed hydrocarbon from two charging events. Initially, during the Middle–Late Triassic period, both Block 1 and the Xinguang Gas Field were charged with mature oil. Later, from the Late Cretaceous to Early Neogene periods, a secondary charging of highly mature oil and gas occurred in the Xinguang Gas Field, while the reservoir in Block 1 remained largely unchanged. In the co-evolution of reservoir fluid composition, temperature, and pressure, the phase transitions of the hydrocarbon fluids in the Xinguang Gas Field passed through several stages, including liquid black oil (231.9–80.3 Ma), liquid volatile oil (80.3–79.1 Ma), vapor–liquid two-phase volatile oil (79.1–78.3 Ma), vapor–liquid two-phase condensate gas (78.3–69.1 Ma), and supercritical condensate gas (69.1 Ma–present). Full article

In order to clarify the pore evolution and coupling characteristics with hydrocarbon charging in the deep-buried ultra-tight sandstone reservoirs of the second member of Xujiahe Formation (hereinafter referred to as the Xu 2 Member) on the eastern slope of the Western Sichuan Depression, this study integrates burial history and thermal history with analytical methods including core observation, cast thin section analysis, scanning electron microscopy, carbon-oxygen isotope analysis, and fluid inclusion homogenization temperature measurements. The Xu 2 Member reservoirs are predominantly composed of lithic sandstones and quartz-rich sandstones, with authigenic quartz and carbonates as the main cementing materials. The reservoir spaces are dominated by intragranular dissolution pores. The timing of reservoir densification varies among different submembers. The upper submember underwent compaction during the Middle-Late Jurassic period due to the high ductility of mudstone clasts and other compaction-resistant components. The middle-lower submembers experienced densification in the Late Jurassic period. Late Cretaceous tectonic uplift induced fracture development, which enhanced dissolution in the middle-lower submembers, increasing reservoir porosity to approximately 5%. Two distinct phases of hydrocarbon charging are identified in the Xu 2 Member. The earlier densification of the upper submember created unfavorable conditions for hydrocarbon accumulation. In contrast, the middle-lower submembers received hydrocarbon charging prior to reservoir densification, providing favorable conditions for natural gas enrichment and reservoir formation. Three sweet-spot reservoir development patterns are recognized: paleo-structural trap + (internal source rock) + source-connected fracture assemblage type, paleo-structural trap + internal source rock + late-stage fracture assemblage type, and paleo-structural trap + (internal source rock) + source-connected fracture + late-stage fracture assemblage type. Full article

The tight sandstone reservoirs within the Oligocene Huagang Formation represent one of the most promising exploration targets for future hydrocarbon development in the Xihu Depression of the East China Sea Basin. The reservoir has complex sedimentary and diagenetic processes. In this paper, a variety of methods, such as microscopic image observation, particle size analysis, X-ray diffraction measurement (XRD), heavy minerals, carbon and oxygen isotopes of cement, the homogenization temperature of fluid inclusions, zircon (U-Th)/He isotopes, and high-pressure mercury intrusion (HPMI), are used to analyze the thermal evolution history, diagenetic evolution process, and the causes of differences in diagenetic processes and high-quality reservoirs. This study shows that the provenance of the southern region is derived from western metamorphic rock, while that of the northern region is dominated by northern metamorphic rock, including some eastern volcanic rock. The northern region exhibits a stronger compaction and lower porosity, primarily due to a greater proportion of volcanic rock provenance. Additionally, coarse-grained lithofacies exhibit a higher quartz content and lower proportions of clay minerals and lithic fragment compared to fine-grained lithofacies, consequently demonstrating greater resistance to compaction. The Huagang Formation reservoir has three stages of carbonate cementation, two stages of quartz overgrowth, and two stages of fluid charging. The two stages of fluid charging correspond to two stages of organic acid dissolution. In the northern region, the geothermal gradient is high, and the burial depth is large, so the diagenetic event occurred earlier and is now in the mesodiagenesis B stage, while in the southern region, the geothermal gradient is low, and the burial depth is small and is now in the mesodiagenesis A stage. The southern distributary channel sands and northern high-energy braided channel sands constitute high-quality reservoirs, characterized by a coarse grain size, large pore throats, and minimal cement content. Full article

The Ordovician carbonate formations in the Ordos Basin provide a crucial stratigraphic unit for prospective oil and gas exploration. Significant progress has been made in the exploration of natural gas within the Ordovician subsalt formations. Nonetheless, understanding its accumulating properties requires additional investigation. Clarifying the formation periods of the carbonate rock reservoirs in the Majiagou Formation of the basin can furnish a theoretical foundation for advanced exploration of carbonate rock oil and gas. This study uses fluid inclusion petrography, laser Raman spectroscopy, and microscopic temperature measurement methods, along with information about the basin’s history of burial and thermal evolution, to look at the oil and gas charging periods of Majiagou Formation reservoir in the central-eastern basin. The results show that there are two stages of hydrocarbon inclusions. The first stage has blue fluorescence and temperature peaks between 85 and 95 °C in the central basin and between 105 and 115 °C in the eastern basin. For the second stage, no fluorescence can be observed. Meanwhile, the temperature peaks are between 175 and 185 °C in the central basin, and between 165 and 175 °C in the eastern basin. In the central part of the basin, oil charging began in the Late Triassic (231–203 Ma) and reached the gas generation stage in the Late Early Cretaceous (121–112 Ma), peaking in natural gas charging. In contrast, the reservoirs in the eastern part of the basin experienced a primary oil charging stage in the Early Jurassic (196–164 Ma) and entered the gas generation stage in the Late Early Cretaceous (110–101 Ma). The hydrocarbon charging process in the study area is mainly controlled by the thermal evolution history of the basin. The study determines that the central basin enters the threshold of hydrocarbon generation earlier than the eastern basin, leading to earlier oil and gas charging. Full article

The light oil wells within the Neogene Shawan Formation have been extensively drilled in the Chepaizi Uplift, reflecting an increase that provides new targets for unconventional resources in the Junggar Basin of northwestern China. However, the original sources of light oil remain controversial, as several source rocks could potentially generate the oil. For this study, we collected light oils and sandstone cores for biomarker detection using gas chromatography–mass spectrometry (GC-MS). Additionally, fluid inclusions were observed and described, and the homogenization temperatures of saltwater inclusions were measured to confirm the oil charging history in conjunction with well burial and thermal history analysis. Based on these geochemical characteristics and carbon isotopic analysis, the results indicate that light oil in the Chepaizi Uplift zone primarily originates from Jurassic hydrocarbon source rocks in the Sikeshu depression, with some contribution from Cretaceous hydrocarbon source rocks. Jurassic hydrocarbon source rocks reached a peak of hydrocarbon generation in the middle to late Neogene. The resulting crude oil predominantly migrated along unconformities or faults to accumulate at the bottom of the Cretaceous or Tertiary Shawan Formation, forming anticlinal or lithologic oil reservoirs. Some oil reservoirs contain mixtures of Cretaceous immature crude oil. During the Neogene light oil accumulation process, the burial rate of reservoirs was high, and the efficiency of charging and hydrocarbon supply was relatively high as well. Minimal loss occurred during the migration of light oil, which significantly contributed to its rapid accumulation. Full article

The Yanchang Formation of the Triassic in the Ordos Basin comprises various stratigraphic intervals. The Chang 8 reservoir represents a significant oil-producing section of the Yanchang Formation, and its hydrocarbon accumulation mechanism is complex. In this study, we analyzed the diagenetic evolution and reservoir-forming stages of the Chang 8 member of the Yanchang Formation in the Late Triassic in the Fuxian area, the southern Ordos Basin, via thin-section casting, scanning electron microscopy (SEM), X-ray diffraction, and fluid inclusion petrology and homogenization temperature analyses. The relationship between the petrogenesis and hydrocarbon charging history was analyzed, which provided guidance for identifying and predicting the hydrocarbon reservoir distribution. The results show that the main diagenesis types of the Chang 8 reservoir are compaction, cementation, dissolution, and metasomatism. The comprehensive analysis of the reservoir mineral types, diagenesis, diagenetic sequence, and thermal evolution degree of organic matter shows that the Chang 8 reservoir of the Yanchang Formation is in the A stage of the middle diagenesis stage. Under the overpressure of hydrocarbon generation, oil and gas migrated into the Chang 8 reservoir along fractures and connected pores. The earlier-stage hydrocarbon charging occurred after compaction and later than the early clay film formation and early calcite precipitation, and it also occurred earlier than or simultaneously with the quartz overgrowth. The later hydrocarbon charging occurred after the significant quartz overgrowth and late calcite pore filling. Depending on the homogenization temperature and salinity, the fluid inclusions can be divided into two types: low-temperature, low-salt (90–105 °C, 1.4%–11.2%) fluid inclusions and high-temperature, high-salt (115–120 °C, 2.2%–12.5%) fluid inclusions. According to the analysis of the evolution of the burial history, hydrocarbon charging in the Chang 8 reservoir of the Yanchang Formation in the Fuxian area occurred in two consecutive periods: 133~126 Ma and 122~119 Ma, demonstrating one-scene, two-stage reservoir formation, characterized by simultaneous reservoir densification and hydrocarbon charging. In this research, we precisely ascertained the regional diagenetic characteristics and patterns and periods of hydrocarbon charging, thereby furnishing crucial evidence that deepens the comprehension of sedimentary basin evolution. Full article

The process of coal measure gas accumulation is relatively complex, involving multiple physicochemical processes such as migration, adsorption, desorption, and seepage of multiphase fluids (e.g., methane and water) in coal measure strata. This process is constrained by multiple factors, including geological structure, reservoir physical properties, fluid pressure, and temperature. This study used Well Z-7 in the Qinshui Basin as the research object as well as numerical simulations to reveal the processes of methane generation, migration, accumulation, and dissipation in the geological history. The results indicate that the gas content of the reservoir was basically zero in the early stage (before 25 Ma), and the gas content peaks all appeared after the peak of hydrocarbon generation (after 208 Ma). During the peak gas generation stage, the gas content increased sharply in the early stages. In the later stage, because of the pressurization of the hydrocarbon generation, the caprock broke through and was lost, and the gas content decreased in a zigzag manner. The reservoirs in the middle and upper parts of the coal measure were easily charged, which was consistent with the upward trend of diffusion and dissipation and had a certain relationship with the cumulative breakout and seepage dissipation. The gas contents of coal, shale, and tight sandstone reservoirs were positively correlated with the mature hydrocarbon generation of organic matter in coal seams, with the differences between different reservoirs gradually narrowing over time. Full article

The Ahdeb oil field is located in the southwestern part of the Zagros fold deformation zone. The study of the model of the formation of the oil reservoir in this field will be helpful to deepen the pattern of hydrocarbon distribution in this zone. In this paper, we use the seismic data of the Ahdeb oil field to recover the tectonic evolution history of the field. Under neotectonic movement, the oil field formed in the early stage, migrated to the high point in the late stage, and finally entered the present formation. From here, for the oil-bearing inclusions within the reservoir, the photometric absorption values of the organic matter groups were measured by infrared spectroscopy. Their ratios were used to evaluate the maturity, thus discovering two phases of oil charging. Finally, using the hydrocarbon generation history and tectonic evolution history, combined with the oil and gas transportation periods in the reservoir, we deduce that the reservoir formation mode in the area is a two-phase gathering and final adjustment formation mode. This understanding of the hydrocarbon formation patterns will promote oil and gas exploration in this zone. Full article

The complexity of petroleum phases in deep formations plays an important role in the evaluation of hydrocarbon resources. Pressure is considered to have a positive impact on the preservation of liquid oils, yet direct evidence for this phenomenon is lacking in the case of deep reservoirs due to late destruction. Here, we present fluid-inclusion assemblages from a deep reservoir in the Tazhong area of the Tarim Basin, northwestern China, which formed as a direct consequence of fluid pressure evolution. Based on thermodynamic measurements and simulations of the coexisting aqueous and petroleum inclusions in these assemblages, the history of petroleum activities was reconstructed. Our results show that all analyzed fluid-inclusion assemblages demonstrated variable pressure conditions in different charging stages, ranging from hydrostatic to overpressure (a pressure coefficient of up to 1.49). Sequential petroleum charging and partial oil cracking may have been the main contributors to overpressure. By comparing the phases of petroleum and fluid pressures in the two wells, ZS1 and ZS5, it can be inferred that overpressure inhibits oil cracking. Thus, overpressure exerts an important influence on the preservation of liquid hydrocarbon under high temperatures. Furthermore, our results reveal that the exploration potential for liquid petroleum is considerable in the deep reservoirs of the Tarim Basin. Full article

The marine carbonates in the Ordovician Majiagou Formation in the Ordos Basin have significant exploration potential. Research has focused on their thermal history and hydrocarbon accumulation stages, as these are essential for guiding the exploration and development of hydrocarbons. In this paper, we study the thermal evolution history of the carbonate reservoirs of the Ordovician Majiagou Formation in the east-central Ordos Basin. Furthermore, petrographic and homogenization temperature studies of fluid inclusions were carried out to further reveal the hydrocarbon accumulation stages. The results demonstrate that the degree of thermal evolution of the Ordovician carbonate reservoirs is predominantly influenced by the deep thermal structure, exhibiting a trend of high to low values from south to north in the central region of the basin. The Fuxian area is located in the center of the Early Cretaceous thermal anomalies, with the maturity degree of the organic matter ranging from 1 to 3.2%, with a maximum value of 3.2%. The present geothermal gradient of the Ordovician Formation exhibits the characteristics of east–high and west–low, with an average of 28.6 °C/km. The average paleo-geotemperature gradient is 54.2 °C/km, the paleoheat flux is 55 mW/m², and the maximum paleo-geotemperature reaches up to 270 °C. The thermal history recovery indicates that the Ordovician in the central part of the basin underwent three thermal evolution stages: (i) a slow warming stage before the Late Permian; (ii) a rapid warming stage from the end of the Late Permian to the end of the Early Cretaceous; (iii) a cooling stage after the Early Cretaceous, with the hydrocarbon production of hydrocarbon source rocks weakening. In the central part of the basin, the carbonate rock strata of the Majiagou Formation mainly developed asphalt inclusions, natural gas inclusions, and aqueous inclusions. The fluid inclusions can be classified into two stages. The early-stage fluid inclusions are mainly present in dissolution holes. The homogenization temperature is 110–130 °C; this coincides with the hydrocarbon charging period of 210–165 Ma, which corresponds to the end of the Triassic to the end of the Middle Jurassic. The late-stage fluid inclusions are in the dolomite vein or late calcite that filled the gypsum-model pores. The homogenization temperature is 160–170 °C; this coincides with the hydrocarbon charging period of 123–97 Ma, which corresponds to the late Early Cretaceous. Both hydrocarbon charging periods are in the rapid stratigraphic warming stage. Full article

Abnormally high pressures are currently limited and locally developed in the Funing Formation of the Gaoyou Sag, Subei Basin, eastern China, but the paleopressure and its evolutionary history remain unclear. Based on the determination of hydrocarbon charging periods by performing systematic fluid inclusion analysis on sixteen core samples from the Funing Formation, thermodynamic modeling with fluid inclusion data was adopted to reconstruct the paleopressure and redisplay its evolutionary history throughout geological time. Results showed that the Funing Formation experienced two episodes of hydrocarbon charging periods. Episode 1 occurred with the charging of lower maturity oils in the period from 52.8 Ma to 49.5 Ma, which was recorded by yellow-fluorescing oil inclusions. Episode 2 happened with the charging of higher maturity oils in the period from 47.0 Ma to 37.0 Ma, which was characterized by blue-fluorescing oil inclusions. Each episode was an abnormally high-pressured hydrocarbon charging process. The pressure coefficient of Episode 1 reached as high as 1.44, while that of Episode 2 reached as high as 1.40. The current formation pressure is the evolutionary result of paleopressure after a process of rapid increasing and decreasing and slow increasing and is not as high as what it reached during the hydrocarbon charging periods. This work is valuable for the exploration of conventional clastic oil reservoirs and unconventional shale oils in the Funing Formation. Full article