Petroliferous Basins Research Articles

Fluid–rock interaction controlled by integrated hydrothermal fluid and fault: Implications for reservoir development

Hydrothermal activity is prevalent in petroliferous basins, particularly in fractured reservoirs. Hydrothermal fluids enter the reservoirs and cause significant fluid–rock interaction, which ultimately controls reservoir development. The Mahu Sag in western China is a hydrocarbon-rich region where hydrothermal fluids and faults control the reservoirs, making it challenging to understand the development mechanism of the shale reservoirs. This study focused on the Fengcheng Formation in the Mahu Sag. Based on a range of previous lithological test results, numerical models of hydrothermal fluid charging were established to explore differences in fluid–rock interactions under varying temperature, fluid, and flow rates. Results revealed that within a specific range, increasing temperature and Mg2+ concentration promoted hydrothermal processes. The hydrothermal flow rate influenced ion accumulation on the fluid-rock contact surface, thus controlling mineral dissolution rates. In a certain range, when the flow rate is increased by 3 times, the growth rate of dolomite content is increased by more than 15 times. Hydrothermal fluid flowing near the fault underwent chemical action more readily than in other areas. The influence of hydrothermal fluid and fault on reservoir development was both constructive and destructive. The decrease and increase of porosity are 30 % and 25 %, respectively. This study could provide a theoretical basis for identifying factors influencing shale reservoir development.

Thermochronological constraints on the evolution of the Bongor Basin, Chad

The Bongor Basin is an important petroliferous basin in the Western and Central African rift system. The basin's evolution history is featured with a strong tectonic inversion during the Late Cretaceous, which resulted in its unique basin structure and hydrocarbon accumulation pattern. However, due to the complex process of repeated cooling and heating, single sample bedrock thermochronology can hardly provide accurate constraints to its thermal evolution history. In this paper, nine granitic core samples from the crystalline basement in five wells on the northern slope of the Bongor Basin were analyzed using multiple thermochronological methods (apatite U-Th/He, apatite fission tracks and length distribution, apatite U-Pb dating) as well as vertical profiles to obtain a more accurate thermal history. The results show that the samples from all five wells underwent four stages of thermal history: from ∼600 Ma to 135 Ma, the samples cooled continuously from 600 °C to near-surface temperatures; from ∼135 Ma to 100 Ma, the samples were heated rapidly; from 100 Ma to 60–80 Ma, the samples cooled rapidly; and after that, the samples experienced slow differential heating and cooling. The thermal history results show that the key time for the strong inversion of the Bongor Basin was between 80 and 90 Ma when the basin was uplifted and exhumed as a whole, while samples in different fault blocks underwent differential uplift and subsidence since the Paleogene.

Tectonics of Cauvery basin (India) in onshore and offshore portions

Morphometric studies coupled with geophysical investigations from petroliferous basins provide valuable information about tectonics of the regions. We deduce six morphologic parameters from the River Cauvery's designated (sub)watersheds and perform dendrogram clustering analysis. The main channels of the (sub)watersheds showcase steeper gradient and meandering nature with less concavity. On the other hand, the distributaries portray lesser gradient and straight nature with greater concavity. From the offshore region of the Cauvery basin, we perform gravity modeling. The results show variations in gravity values from low to high, -150 to 50 mGal probably because of the basement ridge-depression features. This anomaly orientation indicates the extension of the sub-basin in the region. A strong NE-SW gravity trend possibly suggests a high-density plug at mid-crust. The low gravity values near the Vedaranyam region indicate low-density rocks within the basement. Places of high gravity anomaly show a decrease in bathymetry depth and vice versa. This indicates isostatic compensation of the Moho geometry, possibly due to crustal thinning in the offshore areas. Isostatic regional gravity fields are manifested by Moho relief and can have implications on the lithospheric mechanical strengths. Bathymetric studies indicate multi-directional slopes. Relatively flat areas can indicate depocenters. E-W trending lineaments mapped on the Precambrian basement from a portion of the study area is presumably a manifestation of Cauvery Shear zone, which also persists in the offshore region.

Helium enrichment theory and exploration ideas for helium-rich gas reservoirs

Using gas and rock samples from major petroliferous basins in the world, the helium content, composition, isotopic compositions and the U and Th contents in rocks are analyzed to clarify the helium enrichment mechanism and distribution pattern and the exploration ideas for helium-rich gas reservoirs. It is believed that the formation of helium-rich gas reservoirs depends on the amount of helium supplied to the reservoir and the degree of helium dilution by natural gas, and that the reservoir-forming process can be summarized as “multi-source helium supply, main-source helium enrichment, helium-nitrogen coupling, and homogeneous symbiosis”. Helium mainly comes from the radioactive decay of U and Th in rocks. All rocks contain trace amounts of U and Th, so they are effective helium sources. Especially, large-scale ancient basement dominated by granite or metamorphic rocks is the main helium source. The helium generated by the decay of U and Th in the ancient basement in a long geologic history, together with the nitrogen generated by the cracking of the inorganic nitrogenous compounds in the basement rocks, is dissolved in the water and preserved. With the tectonic uplift, the ground water is transported upward along the fracture to the gas reservoirs, with helium and nitrogen released. Thus, the reservoirs are enriched with both helium and nitrogen, which present a clear concomitant and coupling relationship. In tensional basins in eastern China, where tectonic activities are strong, a certain proportion of mantle-derived helium is mixed in the natural gas. The helium-rich gas reservoirs are mostly located in normal or low-pressure zones above ancient basement with fracture communication, which later experience substantial tectonic uplift and present relatively weak seal, low intensity of natural gas charging, and active groundwater. Helium exploration should focus on gas reservoirs with fractures connecting ancient basement, large tectonic uplift, relatively weak sealing capacity, insufficient natural gas charging intensity, and rich ancient formation water, depending on the characteristics of helium enrichment, beyond the traditional idea of searching for natural gas sweetspots and high-yield giant gas fields simultaneously.

Distributions and accumulation mechanisms of helium in petroliferous basins

Distributions and accumulation mechanisms of helium in petroliferous basins

Petrological and geochemical evidences for anaerobic and thermochemical oxidations of methane in petroliferous basins

Methane oxidation affects hydrocarbon accumulation and carbon cycling with important geological and paleoclimatic responses. However, the petrological and geochemical evidences that can clearly discern anaerobic (AOM) and thermochemical (TOM) oxidations in petroliferous basins are unclear, causing the disputes if these two processes can take place in specific conditions. Here, the Baikouquan Formation (T1b) in the Mahu Sag, Junggar Basin, China, was used as the first case study for comprehensive petrological and geochemical analyses to explore this scientific issue. Results indicate that the two main types of T1b calcite cement record different methane oxidation mechanisms. Calcite cements filling intergranular pores were formed during early diagenesis in relatively shallow-burial stages, through AOM with high-valence Mn oxides as electron acceptors, and with compositions of −47.5 ‰ < δ13C < −30.9 ‰, 1.1 wt% < MnO < 5.8 wt%, and 0.02 wt% < FeO < 0.13 wt%. Calcite cements filling intragranular dissolution pores were formed through TOM with high-valence Mn oxides as electron acceptors during mesogenesis during relatively deep-burial stages, with compositions of −39.7 ‰ < δ13C < −14.3 ‰, 0.43 wt% < MnO < 11.00 wt%, and 0.03 wt% < FeO < 0.36 wt%. Thus, methane oxidation underwent a transition from AOM to TOM with increasing depth, as recorded by the calcite cements with different occurrences. This transition may be a common feature of clastic strata in petroliferous basins.

Cenozoic faulting leading to petroleum escape in SW Ordos Basin, China: Evidence from fault-related calcite in situ U-Pb dating, rare earth elements and fluid inclusions

Understanding the link between fault activity and movement to petroleum escape is crucial for assessing the petroleum exploration potential in sedimentary basins. As a significant petroliferous basin in China, the Ordos Basin hosts the world-class uncompartmentalized Jingbian natural gas field within the Ordovician marine carbonate reservoirs. However, the role of the unique exhumation history and the Cenozoic faulting in the formation of such large-scale oil-gas fields remain unclear. Our study combines fault-related calcite U-Pb dating with fluid inclusions analysis offers a unique opportunity to trace petroleum leakage along the the carbonate strata brittle fault zones in the SW Ordos Basin. Calcite samples collected from the carbonate fault zone and across the Ordovician carbonate strata in the SW Ordos Basin reveal clear positive Eu anomaly, slight positive Y anomaly, the lack of positive La and Gd anomalies, and the absence of a negative Ce anomaly. The Y/Ho ratios range from 29 to 36, with an average value of 32, indicating calcite formation in a hydrothermal environment during fault activation. U-Pb dating of these fault-related calcites yields ages of 32.8 ± 3.3 Ma and 23.7 ± 7.4 Ma. Raman spectroscopy of fluid inclusions reveals the presence of CH4 gas, coeval with the fault-related calcite. The homogenization temperatures (Th) of aqueous inclusions coeval with CH4 inclusion from two calcite veins range from 140.0 to 172.4 °C (average Th = 157.8 °C, n = 16) and 127.7–154.3 °C (average Th = 142.2 °C, n = 18). Low temperature thermochronology suggest rapid uplift since 40 Ma, potentially linked to fault activity. The Cenozoic erosion rate was 0.06 mm/y during the ∼9 Myr period from 32.8 to 23.7 Ma in the SW Ordos Basin, suggesting that Cenozoic faulting may have created permeable pathways for petroleum escape. This study provides a temporal link between Cenozoic uplift, faulting, and petroleum loss in SW Ordos Basin.

The Implications of Seeping Hydrocarbon Gases in the Gunsan Basin, Central Yellow Sea, off the Southwest of Korea

A detailed analysis of high-resolution (3.5 kHz) chirp seismic profiles acquired in the Gunsan Basin of the central Yellow Sea revealed that hydrocarbon gases are actively seeping via the formation of many plumes. The uppermost sedimentary layer was acoustically confirmed to be fully or partially charged with gases. Somewhat favored by the low-tide period, episodic gas seepage is mainly associated with the underlying fault systems of Cretaceous-Cenozoic sedimentary strata in the southwestern part of the basin. Catastrophic gas expulsion seems to have formed a crater at the sidewall of a sedimentary ridge and two diapirs. Here, methane is poorly concentrated but rich in the heavy carbon isotope (δ13C, −52.6‰ to −44.7‰ The Vienna Peedee Belemnite [VPDB]), indicating that methane formed mainly through biodegradation of heavy oils at depth remains in the shallow sediments following its expulsion. Episodic rapid upward advection of porewater is also manifest by unmixed heavy methane trapped in the upper part of the primary biogenic methane (δ13C, about −90‰ VPDB)-filled sediment core. These findings imply that the Gunsan Basin fulfills the requirements for possible generation and preservation of oil and gas, like the petroliferous basins of eastern China and the Yellow Sea.

A study on the accumulation model of the Santos basin in Brazil utilizing the source–reservoir dynamic evaluation method

The exploration potential within deep-water petroliferous basins holds great promise for oil and gas resources. However, the dearth of geochemical and isotopic data poses a formidable challenge in comprehending the intricate hydrocarbon charging processes, thereby impeding the comprehensive understanding of hydrocarbon accumulation mechanisms and models. Consequently, the establishment of robust source–reservoir relationships in deep-water petroliferous basins represents a pivotal challenge that significantly influences the exploration strategies and the comprehension of hydrocarbon enrichment dynamics within such basins. In this study, we introduce a novel approach, termed the “source–reservoir dynamic evaluation method,” tailored to investigate reservoir accumulation models in deep-water petroliferous basins. This method uses basin simulation technology to recover the thermal evolution history and hydrocarbon generation and expulsion history of source rocks, and on this basis delimits the hydrocarbon kitchen range. At the same time, the maturity of source rocks corresponding to crude oil and natural gas in typical reservoirs is calculated. Then, when the thermal evolution degree of source rocks adjacent to the reservoir reaches this maturity, the corresponding geological period is the main charging period of hydrocarbon. As a typical deep-water petroliferous basin, the Santos Basin in Brazil has abundant oil and gas reservoirs under the thick salt rock, but there are still some fundamental problems such as unclear oil–gas accumulation process and model. Therefore, in this paper, the main charging periods of typical hydrocarbon reservoirs are determined based on the internal relationship between the thermal evolution history of the main source rocks and the maturity of crude oil and natural gas, and then the hydrocarbon accumulation process is analyzed and the dynamic accumulation model is established. Finally, the favorable prospecting direction is pointed out. The results show that the oil and gas in the Barra Velha Formation in the Santos basin are mainly derived from the Itapema Formation lacustrine shale source rock, and the source rock is mainly developed in the Eastern Sag of the Central Depression, and its main hydrocarbon generation period is from the deposition period of Florianopolis Formation to the deposition period of Santos Formation. The main hydrocarbon expulsion period was from the deposition period of the Santos Formation to the Early deposition of the Iguape Formation. The oil and gas in the Barra Velha Formation were mainly charged from the Late deposition period of the Santos Formation to the Early deposition period of the Iguape Formation. During this period, the hydrocarbon migrated vertically along the normal fault formed in the rift period to the trap of the adjacent inheritance structural highs and accumulated in the reservoir, which was dominated by the accumulation model of the “lower generation-upper reservoir-salt cap”. Since the Barra Velha Formation has the characteristics of near-source accumulation, based on the hydrocarbon expulsion center and hydrocarbon expulsion intensity of the source rock of the Itapema Formation, the distribution ranges of 85% and 50% Pre-salt accumulation probability in the Santos basin were calculated by using the quantitative analysis model of the hydrocarbon distribution threshold. It is suggested that the next oil and gas exploration should be carried out in the paleo-structural highs and slope of Class I favorable area (the hydrocarbon accumulation probability is more than 85%) and Class II favorable area (the hydrocarbon accumulation probability is 85–50%).

Characteristics of Oil and Gas Distribution and Controlling Factors of Hydrocarbon Accumulations in the Eocene Pinghu Formation of the Xihu Depression, East China Sea

The Xihu Depression at the shelf of the East China Sea is a petroliferous basin with excellent exploration potential. The Eocene Pinghu Formation has become a recent oil and gas exploration target and as the critical hydrocarbon-bearing stratigraphic layer in the basin. However, studies specifically examining the characteristics of hydrocarbon distribution and the controlling factors of reservoirs in the Kongqueting area remain limited. The lack of in-depth hydrocarbon accumulation model research restricts subsequent exploration. In this paper, based on data from drilling, 3D seismic, well test, and geochemical analysis, we found that coal bed-related hydrocarbon source rocks were widely occurred in the Pinghu Formation in the Kongqueting area. The source rocks provide good hydrocarbon supply of near-source and distant-source to reservoir. The river sands were connected laterally and stacked vertically, forming a pattern characterized by ‘lateral succession and vertical superposition’ indicative of good quality of reservoir. During the deposition period of the Pinghu Formation, two large sets of regional cap rock (P3 and P7) were excellent sealing rock. The sand reservoir was interbedded with shale layers, forming a Mille-feuille type of reservoir-seal pair. Faults formed at the early stage of the formation of basin serve as conduits for hydrocarbon migration, governing both the spatial distribution of hydrocarbon-bearing strata and the types of hydrocarbon accumulations. These faults were instrumental in facilitating the formation of extensive oil and gas accumulations. This paper establishes a hydrocarbon accumulation model in the Kongqueting area, characterized as ‘dual hydrocarbon supply from source, upper oil, and lower gas, good reservoir-seal pair, hydrocarbon migration through fault conduit’.

Origin of horsetail faults in an extensional regime using physical experiments for the Linnan Sag

Horsetail faults and rotational faults, which maintain slight differences, are all important identity markers for strike-slip movement. However, it is difficult to explain why horsetail faults also appear in the extensional regime. Using the Linnan Sag as a reference, physical experiments are conducted to reproduce the formation processes of horsetail faults in the extensional regime. Characteristics of these horsetail faults include: (1) horsetail faults are the product of strain superposition during two phases of noncoaxial extension; (2) preexisting faults generated in the initial stage may reactivate by the combined elongation of dip-slip motion, followed by oblique-slip faulting at the middle-late stage, thus becoming the principal fault of the horsetail faults; this initial distance is obviously less (approximately 46%) than its distance during the middle-late stage; (3) a large number of new dip-slip faults appear at the tip of the principal fault in the middle-late stage, spatially connecting with the principal fault to form the horsetail faults; and (4) other preexisting faults that intersect the principal fault are not necessary for forming the horsetail faults but their presence may make the principal fault prone to segmentation. Therefore, although horsetail faults in the extensional and strike-slip regimes are similar in shape, their formation conditions and fault properties are very different. Understanding the characteristics of the horsetail faults in the extension regime contributes to further study related to oil and gas migration and accumulation in the Petroliferous basin.

Helium resource in the petroliferous basins in China and its development prospects

Helium resource in the petroliferous basins in China and its development prospects

Noble gas characteristics of microbial gas in the Qaidam Basin, China: Implications for helium enrichment processes

Helium is a critical, strategic and nonrenewable resource with limited reserves and unstable supplies. However, the helium sources and migration processes in petroliferous basins remain unclear. The Qaidam Basin features multiple reservoir layers, multiple genetic types of natural gas, and varying helium concentrations, providing an ideal natural laboratory for understanding the helium enrichment processes. Here, we present the original noble gas isotopic compositions and major gas components of 11 microbial gas samples from three gas layers in the Sebei No.1 gas field, eastern Qaidam Basin, China. The helium isotopic ratios range from 0.007 to 0.057 Ra, reflecting a predominantly crustal source. The Quaternary Sebei microbial gas features much lower helium concentration (0.0003–0.001%), 21Ne/22Ne ratio (0.031–0.034), and 40Ar/36Ar ratio (292–380) than thermogenic natural gases in the Qaidam Basin. The middle gas layer (II) of the Sebei gas field features higher 21Ne/22Ne and 40Ar/36Ar ratios than the top and bottom gas layers, displaying positive correlations with higher 4He groundwater concentrations before degassing, as calculated from 4He/20Ne ratios and 20Ne concentrations in air-saturated water. However, the correlations between the 4He contents in natural gas and the 21Ne/22Ne and 40Ar/36Ar ratios are unclear, suggesting that 4He dissolves into the groundwater system before degassing into a gas reservoir and that the variations in the 4He concentration in the gas phase are caused by the different levels of hydrocarbon dilution. Quantitative calculations of helium production revealed an external helium flux from the crustal basement except for the in-situ production from sedimentary strata even in this broadly-defined self-generating and self-preserving natural gas system. The helium resources in the Qaidam Basin are mainly distributed in tectonically active zones with uplifted pre-Jurassic basement rocks (providing sufficient helium sources), ancient groundwater systems (accumulating more helium) and suitable hydrocarbon production (acting as a carrier gas but diluting helium as slightly as possible).

Fluid inclusion records of oil-cracked wet gas in Permian carbonate reservoirs from the Eastern Sichuan Basin, China

Oil-cracked gas is an important gas resource in petroliferous basins. In theory, oil-cracked gas should be rich in C2+ (i.e., wet gas). However, gas reservoirs of oil cracking origin in the Sichuan Basin (South China) are mainly composed of dry gas. Fluid inclusions record hydrocarbon generation and evolution. Obviously, identifying wet gas inclusions is the key to solving the above controversy. Here, we calibrate the Raman spectroscopic detection limits of ethane and propane (0.007 and 0.016 MPa, respectively) and demonstrate that Raman spectroscopy is a powerful method to identify C2+-bearing inclusions. Based on this technique, C1–C2–C3-bearing wet gas inclusions (C1/ƩCi = 0.90–0.93) are identified in calcite cements of the Permian Changxing Formation carbonate reservoir in the Eastern Sichuan Basin. These inclusions are direct geological evidence of oil-cracked gas because the calcite cement precipitated after the formation of pyrobitumen. Furthermore, reconstruction of the temperature-pressure-composition evolutions of calcite-hosted (Changxing Formation) and quartz-hosted gas inclusions in the Ordovician Wufeng–Silurian Longmaxi Formation black shale indicates that high pressure can effectively retard the cracking of C2+ gas hydrocarbons. Differences in gas composition and δ13CCH4 signature between reservoir gas and inclusion gas lead us to conclude that large-scale oil cracking occurred during the Early–Middle Jurassic in the Permian Changxing carbonate reservoir. Nevertheless, oil-cracked gas escaped during the evolution of the paleo-gas reservoir. Formation of the current dry gas reservoir can be attributed to the continuous mixing of late-stage kerogen pyrolysis gas.

Determining complex petroleum migration pathways along faults and sandbodies: a new method and application

Introduction: The reservoir-forming rule in the paleo-slope zone outside petroliferous basins’ source kitchens of the eastern basin in China is unclear, manifested in the distribution of oil and gas in complex multi-layers. This study focuses on petroleum migration along faults and sandbodies to clarify this question and improve the exploration efficiency of petroleum in areas with similar geological conditions.Method: We summarized two models of petroleum migration based on two factors: the connected sandbodies and the vertical unsealing faults. Model I is conducive to the migration of hydrocarbons within a single layer, while Model II is conducive to the vertical migration of hydrocarbons across layers. Combining the means for evaluating fault sealing and sandbody connectivity, integrating these models could form a set of characterization methods for the distribution of the complex fluid migration pathways.Results: This method is applied to characterize the complex multilayer migration pathways distribution in the first and second members of the Shahejie Formation in the central-southern area of the Wen’an Slope in the Baxian Sag, Jizhong Depression, Bohai Bay Basin, China. The results show that, in the first and second members of the Shahejie Formation in the central-southern area of the Wen’an Slope, the area for Model II is mainly distributed in the central-eastern regions. The second member has a Model I area distributed in its western region, and the first member has a Model I area distributed in its centraleastern parts. The latter distribution area is larger than the former. According to hydrocarbon migration analysis, the first member is more conducive to large regional migration and accumulation of hydrocarbons than the second member.Discussion: The predicted result of petroleum migration is consistent with the hydrocarbon distribution found in the central-southern areas of the Wen’an Slope, which is that oil and gas distribution in the first member is significantly greater than that in the second member. Thus, our method is feasible for characterizing the regional distribution of complex multi-layer migration pathways in simple tectonic setting and oil source conditions. However, further research is still needed to increase the effectiveness of present petroleum migration analysis.

Influence of sedimentary processes and fault tectonics on the evolution of submarine canyons in the East Andaman Basin: Insights from high-resolution seismic data analysis

The Andaman Sea Basin, a well-known back-arc spreading centre and a mature petroliferous basin, presents a unique and complex scenario for understanding the interplay of sedimentary processes and fault tectonics on seafloor geomorphology evolution, particularly in the eastern shelf region. This study, using high-resolution 3D seismic data and published exploratory well-seismic interpretation results, aims to establish a comprehensive stratigraphic framework for the Tanintharyi region, spanning the Lower Miocene, Middle Miocene, Upper Miocene, Pliocene, and Quaternary. A submarine canyon system was identified and investigated along the Tanintharyi continental slope within the East Andaman Basin, comprising thirteen slope-confined canyons arranged predominantly in an east-west vertical slope orientation. By analysing seismic reflection features, five distinct seismic facies have been identified, including basal lag (BL), slump and debris-flow deposits (SDFDs), canyon confined sheets (CCSs), laterally inclined packages (LIPs), and channel-levees (CLs). The evolution of this canyon system, a vital focus of this study, can be categorised into three phases based on the morphology and sedimentary structures observed: canyon initiation, canyon extension, and erosion-sedimentation. The findings of this study highlight the critical controlling role of faults in canyon evolution, with the intensity of fault activity displaying a negative correlation with canyon size, indicating the direct impact of faults on geomorphological changes. In addition, the geomorphological changes induced by fault activity have resulted in changes in sediment supply, dispersal, and sedimentation rates, thus significantly impacting the spatial distribution and dimensions of slope-confined canyons within the East Andaman Basin, with far-reaching implications.

The thermal history of Permian carbonate strata reconstructed with clumped isotopes and U–Pb dating: Eastern Sichuan Basin, SW China

The lack of effective paleogeothermometers restricts the study of the thermal history of carbonate strata. Carbonate clumped isotope thermometry and in-situ U–Pb dating are appropriate for reconstructing the thermal history of carbonate strata. Herein, this study analyzed clumped isotope compositions and U–Pb ages of calcite fabrics, including micrite matrix and veins, from Permian carbonate strata in the eastern Sichuan Basin. U–Pb dating of the micrite matrix was performed to rule out the influence of recrystallization and determine the diagenetic age of the samples. Clumped isotope temperatures of the four micrite matrix samples ranged from 102 °C to 137 °C. The maximum paleotemperature derived from a solid-state reordering model was between 210 °C and 220 °C. From all four samples, three calcite veins yielded crystallization temperatures corresponding to 160 ± 10 °C, 60 ± 10 °C, and 29 ± 4 °C, as determined by clumped isotope and solid-state reordering model analyses. In-situ U–Pb dating provided corresponding crystallization ages of 159 ± 17 Ma, 256.6 ± 5.5 Ma, and 17.86 ± 0.8 Ma. The crystallization ages and temperatures of the three calcite veins align well with the thermal history of the Permian strata, indicating a high degree of accuracy. This study introduces a new strategy for reconstructing the thermal history of carbonate strata. The thermal history can be quantified using the constraints of the crystallization ages and temperatures from different stages of calcite veins or cements. This approach is suitable for determining the maturation progress of the source rock and conducting oil and gas exploration in petroliferous basins.

Multi-Factor Controlling Diversity of the Ordovician Hydrocarbon Phase in the Tazhong I Block, Tarim Basin, NW China

The distribution characteristics and main controlling factors of hydrocarbon phases in deep strata from petroliferous basins are important for the evaluation of oil–gas resources and decision-making regarding exploration. The distribution characteristics and controlling factors of the Ordovician hydrocarbon phases are systematically analyzed in the Tazhong I block, Tarim Basin, NW China. The results show that the Ordovician reservoirs in the Tazhong I block are characterized as multi-phase reservoirs with a lateral co-existence of condensates, normal oil reservoirs, and heavy oil reservoirs. From east to west, gas-rich in the fault belt and oil-rich in the platform area are presented. Meanwhile, there are regular variations in the geochemical characteristics of the Ordovician hydrocarbon, showing decreasing trends in the gas/oil ratio (GOR), wax contents, dryness coefficients, methane contents, and methane carbonate isotope values (δ13C1) and an increasing trend in oil densities. Because the same Cambrian–Lower Ordovician source for the Ordovician hydrocarbon is observed in the Tazhong I block, the regular variations in the hydrocarbon phases and geochemical characteristics can be interpreted as records of gas invasion, biodegradation, multi-stage filling, thermal cracking, and thermochemical sulfate reduction (TSR) rather than controlled by the source rock organofacies. This indicated that different kinds of secondary processes for a diversity of the hydrocarbon phase can appear in one region. Our re-construction of the Ordovician hydrocarbon accumulation model in the Tazhong I block encourages future exploration to target gas reservoirs in the fault belt and oil reservoirs in the platform area.

Characteristics and main controlling factors of helium resources in the main petroliferous basins of the North China Craton

Characteristics and main controlling factors of helium resources in the main petroliferous basins of the North China Craton

Evolution processes and diagenetic response of paleo-pore fluids in continental rift basin: A case study of Bonan Sag

Evolution and transport processes of pore fluids are accompanying with the burial process of sedimentary basins. Those processes lead to redistribution of materials and energies, and control the distribution of favorable reservoirs in sedimentary basins too. For petroliferous basins, confirming the evolution processes of pore fluids is useful for favorable reservoirs prediction. In this study, formation waters chemistry characteristics, skeleton particle compositions, and diagenetic products of sandstones were all take into consideration. It is to invert the evolution processes of pore fluids in continental rift basin. This study shows the changes of formation waters, diagenetic products and skeleton particle compositions are regularly with depth. The evolution processes of pore fluids are mainly controlled by basin sinking and uplifting, fluids concentration, mudstones compaction, organic matter evolution, diagenesis. The evolution of pore fluids in Bonan Sag have experienced seven stage: firstly, primary lake water; and then alkaline fluids from mudstone, which is caused by compaction; and then acidic fluids with organic acids; and then the alkaline fluids, which is caused by basin uplifting and water-rock interactions; and then acidic fluids with CO2, which is from cracking of organic matters; and then acidic fluids with CO2/H2S which caused by TSR; at last, alkaline fluids caused by deep buried and water-rock interactions. Changes of pore fluids (physical or chemical) lead parts of minerals in sandstones be unstable, and then dissolved by pore fluids. At the same time, part of dissolved particles in pore fluids reacted with each other, and then precipitated as diagenetic products.