Stages Of Thermal Evolution Research Articles

Comparison of biomarkers in retained oil and expelled oil of lacustrine marlstone determined by hydrous pyrolysis: Application to hydrocarbon migration determination in the tight oil reservoir

Oil in an unconventional tight reservoir is considered to migrate from a very adjacent reservoir or be impregnated in situ within source rocks, but their large hydrocarbon molecular fractions during short‐distance migration in the tight system are poorly understood. In order to explore the evolution characteristics and differences of the geochemical properties, especially the biomarkers, between expelled oil (just detached from source rock and not undergoing long‐distance migration) and retained oil under different thermal evolution stages of lacustrine marlstone. Semi‐open hydrous pyrolysis was conducted on an immature lacustrine marlstone collected from the third member of the Eocene Shahejie Formation in Shulu Sag, Bohai Bay Basin and the hydrocarbon product expelled from and remained in the rock during pyrolysis were collected and analysed with gas chromatography–mass spectrum instrument. The results indicate that the saturates compositions show expelled oil having commonly lower thermal maturity than retained oil because expelled oil is a mixture of multiple‐term hydrocarbon expulsions, while retained oil is the remained final hydrocarbon product of pyrolysis in semi‐open experimental system. The hydrocarbon migration has a significant effect on the maturity‐related parameters distribution such as 20S/(20S + 20R) and αββ/(αββ + ααα) for C29 steranes. Hydrocarbon expulsion enables Ts/(Ts + Tm) ratio in expelled oil is much greater than that of retained oil at lower matural stage. The saturated hydrocarbon maturity biomarkers in retained oil and expelled oil vary in a subtly different pathways with increasing maturity, comparatively the aromatic hydrocarbon biomarkers, such as triaromatic steroids and methyl‐phenanthrene (MPI1 and MPI2), regularly changed during maturation, which is not obviously affected by migration effects and can be used not only for thermal maturity predications but also for oil–oil or oil–source correlation. C29 20S/(20S + 20R) and C29 αββ/(αββ + ααα) commonly are preferable maturity parameters for shale or mudstone, reflecting that mineral matrix and oil in source rock are not affected by migration and supposed to have an oil thermal maturity corresponding to depth. Combined with some tight reservoir cases in North America and China, the biomarker ratios variation along depth and its abnormal value can be used to predict sweet spots in tight reservoirs.

Controlling factors of hydrocarbon accumulation and differential distribution in the western Qaidam Basin, Tibet Plateau

Hydrocarbon distribution in the western Qaidam Basin is complex and characterised by large reserves, dispersed distribution, local enrichment, and multi-layer accumulation. Near the Altyn Tagh Ranges, the traps are mainly oil-filled, whereas far away and near the basin centre, they are gas-filled. With hydrocarbon distribution in the western Qaidam Basin poorly understood, the tectonic evolution, source-rock thermal evolution and space–time configurations were studied using burial history, strata thickness, source-rock generation and expulsion processes, and trap formation. Mode 1 system was characterised by continuous hydrocarbon accumulation, rapid source-rock burial and trap formation early in the basin history resulting in early generation and trapping of low maturity oil and later generation of high maturity oil. Mode 2 was characterised by mid-section hydrocarbon accumulation, steady source-rock burial velocity and trap formation with the traps filled by mature oil and small amounts of gas. Mode 3 was characterised by tail hydrocarbon accumulation, rapid source-rock burial and trap formation late in basin development resulting in traps filled with high-maturity gas. In the Mesozoic–Cenozoic petroleum system, such as the Dina2 condensate gas field, hydrocarbon accumulation was earlier than in the Yingxi Shizigou oilfield belonging to the Cenozoic petroleum system, which was mainly controlled by tectonic evolution and source-rock thermal evolution. The well-matching relationships between hydrocarbon generation–expulsion time and trap formation may create a giant oilfield, an earlier formed trap, later matured source rock and good preservation leading to continuous accumulation of hydrocarbon favourable for exploration. Key points In the western Qaidam Basin, hydrocarbon differential distribution was mainly controlled by source-rock burial history, stratigraphic thickness and trap formation processes. Multi-stage hydrocarbon accumulation characteristics are classified into three modes according to the thermal evolution stage of the source rock. A comparison of hydrocarbon accumulation processes between the Yingxi oilfield in the western Qaidam Basin and Dina 2 gas fields in the Kuqa foreland basin allowed hydrocarbon accumulation modes to be determined.

Modeling of Tectonic-Thermal Evolution of Cretaceous Qingshankou Shale in the Changling Sag, Southern Songliao Basin, NE China

A series of significant shale oil discoveries have been made recently in the Upper Cretaceous Qingshankou Formation in the Songliao Basin, providing a new resource target for shale oil exploration in Northeast China. In this context, an understanding of the tectonic-thermal evolution and maturation history of the Qingshankou Formation is of great significance for shale oil exploration and evaluation. In this study, the thermal history of the Qingshankou Formation since the Late Cretaceous was reconstructed using the paleothermal indicator method. The results indicate that two stages of thermal evolution exist in the southern part of the Songliao Basin: 1) the gradual heating stage during the Late Cretaceous; the heat flow gradually increases during this period and reaches a maximum heat flow value at the end of the Cretaceous. 2) The decline stage since the Neogene; the tectonic activity is relatively stable and the geothermal heat flow is gradually reduced, and the present-day heat flow ranges from 60.1 to 100.7 mW/m2, with an average of 78.2 mW/m2. In addition, the maturity history of the organic-rich shale was reconstructed based on the new thermal history. The Cretaceous Qingshankou shales underwent deep burial thermal metamorphism at the end of the Cretaceous, whereas thermal has faded since the Neogene. The hydrocarbon generation and migration since the Late Cretaceous period of K2qn1 were modeled based on the maturity model. Two main cooling events took place in the late Nenjiang period and the late Mingshui period in the Changling sag. These two tectonic events controlled the structural style and the formation of shale oil reservoirs in the southern Songliao Basin.

Characteristics and the Model of Thermal Evolution and Gas Generation of Late Paleozoic Coal in the Qinshui Basin, Based on Hydrous Pyrolysis.

The Qinshui basin is an important coal-accumulating basin in China, and its Late Paleozoic coal is an important source rock of coalbed methane in the basin. Its thermal evolution and gas generation characteristics determined the grade of coalbed methane resources, especially the coal measure free gas resources in the basin. Late Paleozoic coal samples were collected for organic geochemical analysis, a high-volatile bituminous coal was used for hydrous pyrolysis, to propose the thermal evolution characteristics, gas generation characteristics, thermal evolution, and free gas accumulation model, and the Ordos Basin is compared. The results show that the variation trends of various geochemical parameters are different with the increase in Ro. Hydrous pyrolysis shows that the gas production potential of coal is excellent. The gases produced consist mainly of CH4, C2–, CO2, and H2. C2– is produced only before the simulated temperature of 550 °C, and oil is produced only before the temperature of 500 °C. The thermal evolution stages can be divided into the immature stage, symbiosis stage, wet gas stage, and dry gas stage, and the symbiosis stage can be divided into the preliminary stage and mainly gas stage. Ro, Tmax, (2+3)MP/(1+9)MP, saturated+arene, Vdaf, and H/C can be used as indicators of the thermal evolution stages. On the plane, the distribution of thermal evolution stages of the Shanxi Formation and the Taiyuan Formation is very alike. The gas generating strength of the Taiyuan Formation is higher than that of the Shanxi Formation. The gas generating strength in the north of the Taiyuan Formation is higher, while that in the south of the Shanxi Formation is higher. The second gas generation stage has a good spatio-temporal configuration relationship with accumulation factors, and the gas production is large, which is beneficial to the enrichment of the coal measure free gas resources. Relatively, the Ordos Basin has better prospects for exploration and development.

Influence of different thermal evolution stages on shale pore development

ABSTRACT Different thermal evolution degrees on pore development were studied by cryogenic nitrogen adsorption experiment and microscopic photometric analysis. The organic matter Ro, the pore volume, and the proportion of different pore types are different in the Qingshankou Formation, Longmaxi Formation, and Niutitang Formation. However, the relationship between pore development and thermal evolution is consistent. With increasing the degree of the thermal evolution of organic matter holes appear three different change rules. When the organic matter Ro is less than 1.2, shale porosity is mainly influenced by physical compaction and cementation, shale organic hole filling. With the increase of Ro, the porosity tends to decrease, and when Ro is between 1.2 and 3.0, the organic matter of pyrolysis hydrocarbon generation and organic matter hydrocarbon generation hole and corrosion hole a lot of development, the stage total shale porosity is lower before the rising trend, organic matter porosity increased with the increase of Ro. When Ro is greater than 3.0 (overmaturity stage), graphitization occurs. Under the influence of deep burial and slow compaction, the porosity is decreasing continuously.

Characteristics of coal-measure source rock and its controlling effect on gas-water distribution of tight sandstone of He8 Member in Sulige Gas Province, Ordos Basin

Characteristics of complex gas-water distribution affect the efficient exploration of tight gas. The paper aims at tight sandstone gas-water distribution characteristics of He8 Member in Sulige Gas Province (SGP), describes thickness and TOC of source rocks from Benxi Formation in Carboniferous to the Second Member of Shanxi Formation in Permain, evaluates its hydrocarbon generation potential, discusses its controlling effect on tight sandstone gas-water distribution, and determines the threshold values of Ro and HGI of commercial gas flow wells. Research shows that the coal-measure source rock has the characteristics of extensive and superimposition. The coal seam and dark mudstone is the lithology of source rock, and its Ro is chiefly distributed 1.2% ∼ 2.1% in the stage of high mature thermal evolution, which is mainly type III kerogen. Among them, the thickness of coal seam is mainly ranged from 5 ∼ 15 m with an average of 9.32 m, and its average TOC is 64.08% and the distribution of HGI is (1∼36) ×108 m3/km2. No.8 and No.5 coal seams are relatively stable. The extent of thickness of dark mudstone is mainly between 10m and 30m with an average of 21.2m, and its average TOC is 2.11%, HGI is between (0.2∼10)×108m3/km2. Gas reservoir of He8 Member is tight sandstone lenticular reservoirs with the large-area quasi-continuous distribution. When the gas testing production is less than 1 × 104m3/d, the controlling effect of Ro and HGI are relatively obvious, and its controlling effect is obviously weakened with the increase of gas production. When Ro is more than 1.6%-1.7%, or HGI is larger than 15 × 108m3/km2, the decreasing trend of water/gas ratio is evident, especially in commercial gas flow wells (including high producing gas flow wells). In comparison, the controlling effect of HGI is stronger than Ro. 1.33% and 8 × 108 m3/km2 are the threshold values of Ro and HGI for commercial gas flow wells, respectively.

Simulation of methane adsorption in diverse organic pores in shale reservoirs with multi-period geological evolution

In shale reservoirs, the organic pores with various structures formed during the thermal evolution of organic matter are the main storage site for adsorbed methane. However, in the process of thermal evolution, the adsorption characteristics of methane in multi type and multi-scale organic matter pores have not been sufficiently studied. In this study, the molecular simulation method was used to study the adsorption characteristics of methane based on the geological conditions of Longmaxi Formation shale reservoir in Sichuan Basin, China. The results show that the characteristics of pore structure will affect the methane adsorption characteristics. The adsorption capacity of slit-pores for methane is much higher than that of cylindrical pores. The groove space inside the pore will change the density distribution of methane molecules in the pore, greatly improve the adsorption capacity of the pore, and increase the pressure sensitivity of the adsorption process. Although the variation of methane adsorption characteristics of different shapes is not consistent with pore size, all pores have the strongest methane adsorption capacity when the pore size is about 2 nm. In addition, the changes of temperature and pressure during the thermal evolution are also important factors to control the methane adsorption characteristics. The pore adsorption capacity first increases and then decreases with the increase of pressure, and increases with the increase of temperature. In the early stage of thermal evolution, pore adsorption capacity is strong and pressure sensitivity is weak; while in the late stage, it is on the contrary.

Challenges of terrestrial shale gas exploration and development from Chang 7 shale in the Ordos Basin

There has been great success of marine shale gas exploration and production from Lower Silurian Longmaxi Formation (called Longmaxi shale) in Sichuan Basin, China, while whether commercial gas production could be obtained from lacustrine shales is still a question. The 7th Member of Triassic Yanchang Formation (called Chang 7 shale), which is the exploration target for the only national lacustrine shales gas pilot, was investigated to identify the key issues on the accumulation and development of terrestrial shale gas accumulation. It is considered that there are many differences in terrestrial and marine shales including depositional environment and provenance, distribution characteristics, organic matter types, mineral composition, and pore types. So evaluation standards of the two shales should not be the same. The Longmaxi shale was deposited in deep shelf, widely distributed, stable, mature–overmature (in gas window), presence of plenty micro-pores, brittle, and overpressured, which make it a good condition for shale gas accumulation. The key factors that affect the production of the Longmaxi shale concluded that the shale is rich in organic matter, high thermal evolution, brittle, and overpressured. The Chang 7 shale in Ordos Basin was deposited in deep lake, relative limited distribution, in low stage of thermal evolution (in oil window), high clay mineral content, and conducive to shale gas adsorption. On the basis of comparing the geological features of the two shales, it is found that the shale is richer in the organic matter content than in the Longmaxi shale, while the shale is not mature enough to produce more gas, and the strata pressure is relatively lower which means the shale gas was not preserved very well either. So through this study, it is believed that the shale gas formation condition in the Chang 7 shale may not be as good as in the Longmaxi shale, the absorbed gas may be the future of this shale, and the shale oil should be the focus of petroleum exploration and development in this region.

Geochemical characteristics, genetic types, and source of natural gas in the Sinian Dengying Formation, Sichuan Basin, China

The Sinian Dengying Formation is a key target for deep oil and gas exploration in the Sichuan Basin, China. Natural gas was mainly distributed in the Ziyang–Weiyuan area (ZWA) and the Gaoshiti–Moxi area (GMA). At present, the genetic types and sources of natural gas are still unclear and controversial. The chemical composition, stable carbon isotopes, and biomarkers were used to analyze geochemical characteristics, genetic types, and gas–source relations. The results showed that the composition and content of hydrocarbon gas in the ZWA and GMA were similar. Natural gas was a typical dry gas with an average dry coefficient (C1/C1+) of 0.9991, which reflected higher methane (CH4) content and lower heavy hydrocarbon gas (C2+) content. For nonhydrocarbon gas, CO2 (0.01%–26.34%), N2 (0.03%–24.95%), H2S (0.10%–3.19%), and He (0.01%–0.37%) were mainly distributed. Compared with the GMA, the ZWA was characterized by higher N2 content and lower CO2 content. Although the carbon isotopes had not been reversed, the values of δ13C2–δ13C1 were different between the ZWA and GMA, with the GMA having the higher value. The assemblage relation between the natural gas composition and carbon isotopes indicated that the natural gas type was dominated by oil-cracking gas. Mud-shale in the high maturity stage of thermal evolution greatly influenced on the content of N2 and He. H2S mainly belonged to thermochemical sulfate reduction (TSR), and most of CO2 was formed by deep carbonate metamorphism and TSR. The gas–source relation showed that natural gas in the ZWA was derived from the Cambrian Qiongzhusi Formation and that the gas in the GMA mainly originated from the Sinian Dengying Formation and the Cambrian Qiongzhusi Formation. The established hydrocarbon generation model indicated that the Sinian Dengying Formation is potentially gas-rich.

Effect of organic maturity on shale gas genesis and pores development: A case study on marine shale in the upper Yangtze region, South China

Abstract The marine shale in southern China has undergone complex tectonic evolution with a high thermal evolution degree. Excessive thermal evolution brings certain risks to shale gas exploration and development. With the advancement of experimental methods, the evolution process of shale reservoirs can be better understood from the micro-nanoscale. This work takes the Ordovician-Silurian Wufeng and the first member of Longmaxi Formation in the Sichuan Basin and Lower Cambrian Niutitang Formation in Outer Margin of the Sichuan Basin to study the impact of maturity upon the genesis of shale gas and development features of the reservoir. A series of geochemical research methods, including TOC, gas component and gas isotope, were adopted to study the impact of different thermal evolution stages of organic matter upon the genesis of shale gas. The nanoscale micro-imaging technique, such as FIB-SEM and FIB-HIM, was used to analyze the development of OM-hosted pores. As shown from the results, when R o = 1.2–3.5%, the marine shale gas is dominated by methane and other hydrocarbon gases, since the mixture of cracking gas from liquid hydrocarbons and kerogen-cracking gas cause the carbon isotope reversal. Besides, the pyrobitumen pores characterized by the strong connectivity and storage capacity were primarily developed. When R o > 3.5%, the organic matter is at the graphitization stage. The shale gas is mainly composed of nitrogen at this stage. The nitrogen is originated from the atmosphere and the thermal evolution process, and the OM-hosted pores (pyrobitumen and kerogen pores) characterized by the bad connectivity and storage capacity are developed. Finally, the main component of shale gas, the genesis of shale gas and the pattern of OM-hosted pores under different thermal evolution stages of organic matter are summarized, which provide technical support for the exploration and development of shale gas.

Geochemical assessment of the newly discovered oil-type Shale in the Shuangcheng area of the northern Songliao Basin, China

For the past fifty years, the northern Songliao Basin in China was thought to contain Lower Cretaceous coal-measure and gas-generating shale. Oil-type shales did not receive much attention until oil exploration activities made a breakthrough in the Southern Shuangcheng (SSC) depression. In this study, the geochemical characteristics of the newly discovered K1yc4 (fourth member of the Lower Cretaceous YingCheng Formation) oil-type shale in the SSC depression were analyzed, including the organic matter abundance, organic matter type, thermal maturity, hydrocarbon potential, and sedimentary environment. A total of 393 core samples were collected, and Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), organic petrography, carbon isotope analysis, and constant and trace element analyses were conducted.The K1yc4 shale was determined to have a good to excellent hydrocarbon potential with high TOC values (mostly 2.0–4.0%). The organic matter was mainly from lower hydrobiont, algae, bacteria, and lesser amounts of terrestrial plants. The organic matter is mainly type I to type II based on the hydrogen index (HI) (average HI = 193.36 mg HC/g TOC), the carbon isotopes of the kerogen (mostly −26 to −30‰), and the organic petrography (average sapropelinite + liptinite of 55.0 vol%). The maturity parameters, i.e., Tmax (mean 452 °C) and vitrinite reflectance (0.8–1.1%), suggest that the shale is in the mature thermal evolution stage. The shale's maximum hydrocarbon-generating intensity is up to 713.29 × 104/km2, and its hydrocarbon-expelling intensity is stable at 116.63 × 104/km2. The constant and trace element analyses (Sr, Ba, V, Ni, Cr, Ti) revealed that the organic matter deposition and preservation occurred in a fresh-brackish and dysoxic-anoxic water environment. Volcanic eruptions probably played a vital role in the enrichment of the organic matter in the oil-type shale. In addition, the results of this study provide evidence that the Lower Cretaceous strata in the northern Songliao Basin meet the geological conditions of oil-prone shale, which expands the petroleum exploration horizon in this region.

Insight into the kinetic stabilization of Al0.3CoCrFeNi high-entropy alloys

The AlxCoCrFeNi family of high entropy alloys (HEAs) has received considerable attention due to its promising thermal, mechanical, and corrosion-resistant properties which make it widely suited for aerospace and marine applications. While the formation of secondary phases has been studied at various annealing temperatures, the results have focused on the late stages of precipitation, highlighting the need for the analysis of the intermediate stage precipitation. Here we use in-situ heating in the transmission electron microscope (TEM) complemented by ex-situ characterization of bulk annealed specimens, thermodynamic calculations, and precipitation simulations to study the phase evolution of Al0.3CoCrFeNi. Due to the high density of nucleation sites in the thin film, in-situ TEM reveals the formation of an additional intermediate phase, Co-B2 at 550 °C, where hundreds of hours are predicted for this phase to be shown during ex-situ experiments. At higher annealing temperatures between 700 and 900 °C, in-situ TEM shows the formation of Cr-rich precipitates as the first intermediate phase, followed by NiAl precipitates that form co-precipitates. The formation of these precipitates occurs concurrently, contrary to the findings of previous studies. In conjunction with the in-situ and ex-situ TEM studies, thermodynamic calculations and precipitation simulations have been performed to predict the formation of these phases and are found to support the experimental results. The present work provides new insight into the microstructural evolution of HEAs and reveals the importance of intermediate stages of thermal evolution, enabling an enhanced predictive view of phase evaluation in this class of alloys.

Parameterisations of interior properties of rocky planets

Context.Observations of Earth-sized exoplanets are mostly limited to information on their masses and radii. Simple mass-radius relationships have been developed for scaled-up versions of Earth or other planetary bodies such as Mercury and Ganymede, as well as for one-material spheres made of pure water(-ice), silicates, or iron. However, they do not allow a thorough investigation of composition influences and thermal state on a planet’s interior structure and properties.Aims.In this work, we investigate the structure of a rocky planet shortly after formation and at later stages of thermal evolution assuming the planet is differentiated into a metal core and a rocky mantle (consisting of Earth-like minerals, but with a variable iron content).Methods.We derived possible initial temperature profiles after the accretion and magma ocean solidification. We then developed parameterisations for the thermodynamic properties inside the core depending on planet mass, composition, and thermal state.Results.We provide the community with robust scaling laws for the interior structure, temperature profiles, and core- and mantle-averaged thermodynamic properties for planets composed of Earth’s main minerals but with variable compositions of iron and silicates.Conclusions.The scaling laws make it possible to investigate variations in thermodynamic properties for different interior thermal states in a multitude of applications such as deriving mass-radius scaling laws or estimating magnetic field evolution and core crystallisation for rocky exoplanets.

Two Stages of Thermal Evolution of the Continental Lithosphere

The evolution of the continental lithosphere, unlike the oceanic one, lasts more than 3.5 Ga. This evolution was largely determined by thermal factors, such as the removal of heat from the Earth’s surface, the interaction of the conductive layer of the lithosphere with mantle thermal convection, and the strong dependence of the viscosity of the upper layers of the Earth on temperature. The aim of this work was to simulate the long-term interaction of these factors over a period of several Ga on the basis of the whole-mantle thermal convection equations. In our evolutionary model, the nucleus of continental lithosphere with a thickness of 50 kilometers was inserted in the mantle, which then began to grow in depth due to the reorganization of convection under the continental lid with a conductive heat transfer mechanism. For the self-consistent modeling of the lithosphere thickness changes in time we set the condition of viscosity jump by three orders of magnitude with a decrease in local temperature below 1200°C. The results of successive calculations demonstrated that the initial period of growth of the continental lithosphere due to its cooling, which takes about one Ga, is subsequently replaced by its slow thinning due to the accumulation of heat under a thick heat-insulating lithospheric cover. The calculated maximum of the average thickness of the growing lithosphere, estimated by temperature and viscosity, is 162 kilometers, however, when estimated by the conventional point of intersection of the lithospheric geotherms with mantle adiabat, it is 100 kilometers more. The increase in the average mantle temperature from the heat-insulating effect is about 100 K/Ga and continues both at the stage of the lithosphere thickening and at the subsequent stage of its slow thinning. The mantle warming up due to the presence of continents is one of the competing factors in the global process of the Earth’s secular cooling. The conclusion about the presence of two stages in the evolution of the continental lithosphere clarifies existing ideas about the formation of the current state of the outer layers of the Earth.

Characteristics of the Lower Cambrian Yuertus Formation source rocks in the Tarim Basin, NW China

In this paper, the distribution of source rocks of the lower Cambrian Yuertus Formation in the Tarim Basin is analyzed, a series of organic geochemical characteristics are tested, the characteristics of the source rocks are analyzed, and the thermal evolution and hydrocarbon generation history of the source rocks are simulated. The results show that the distribution of the source rocks is obviously controlled by sedimentary facies; the source rocks are sapropelic organic matter with high abundance and have reached the stage of mature-overmature thermal evolution; those in the eastern depression area have reached the peak of oil generation in the middle Caledonian period, the peak of gas generation in the middle Hercynian period and the end of hydrocarbon generation in the late Hercynian period. In the western uplift area, the source rocks entered the peak of oil generation during late Hercynian period, then entered the stage of gas generation in the early Indosinian period, and then stopped hydrocarbon generation due to uplift and denudation.

Two typical accumulation mechanismsof marine natural gas reservoirs in China: Case comparison between Tarim Basin and Sichuan Basin

Marine basin contains abundant natural gas resources in China, especiallythe Palaeozoic is becoming a hotspot of natural gas exploration, wherea series of large gas fields have been constantly discovered. It isbroad consensusthathigh-post mature source rocks (SRs)is gas-prone and thermal sulphatereduction (TSR) could accelerate the hydrocarbon cracking, which would be the dominant origin of gas enriched in the Palaeozoic of petroliferous Basin in China. In addition, these cracking gas is rich in H2S and CO2, due to the marine source rocksare rich inargillaceous sedimentary and sulfates. Nevertheless, the accumulations of gas reservoirs were obviously different between two giant marine craton in China. Sichuan basin is abundance of marine cracking gas, which was mainly generated around 257-205Ma. But it is rarely found marine oil reservoirs in Sichuan basin. In contrast, abundance of marine condensates are rich in Tarim Basin. Gas washing and migration fractionation effect would be the major formation mechanism of secondary condensates, which coexist with dry gas and normal oil reservoirs. These various reservoirs orderly distribute around source rocks in the Manjia’er sag of Tarim Basin. The origin of marine gases was mainly mixed from the hydrocarbon cracking derived via TSR and the different stages of thermal evolution of marine SRs, as well as portion of humic gas. Therefore, the carbon isotopic composition of diverse gas reservoirs is quite complex and the phenomenon of isotopic reversal δ13C1>δ13C2is pervasive. Eventually, two typical accumulation mechanismsof marine natural gas reservoirshave been established. It could be inferred the exploration of cracking gas is given priority in SichuanBasin and marine secondary condensatesshould be paid more attention during the petroleum exploration in Tarim Basin.

Hydrogen isotope of natural gas from the Xujiahe Formation and its implications for water salinization in central Sichuan Basin, China

Based on the analysis of the molecular composition as well as carbon and hydrogen isotopes of gases from the Upper Triassic Xujiahe and other formations in the Sichuan Basin in China, by combining previous research results and regional geological background, the gas origin, gas source, and significance of hydrogen isotopes are studied. The results show that gas from the Triassic Xujiahe Formation in the Sichuan Basin is mainly hydrocarbon gas. The methane content ranges 67.89%–98.05%, whereas the content of heavy hydrocarbon gas (C2+) ranges 0.42%–16.62%. Meanwhile, the non-hydrocarbon gas content (CO2, N2) is low. Except for the relatively high content of N2 and CO2 in Well Yue121, the average content of N2 and CO2 are 0.82% and 0.26%, respectively. The gas from the Xujiahe Formation in the Yuanba area has a high average dryness coefficient of 0.991, which indicates that it is dry gas. It is also worth noting that gases from other areas of central Sichuan have a dryness coefficient of less than 0.95, which is indicative of wet gas. The δ13C1 value varies from −43.8‰ to −29.2‰, the δ13C2 value ranges from −33.5‰ to −20.7‰, δ13C3 value ranges from −33.6‰ to −19.3‰, and the δ13C4 value ranges from −27.2‰ to −22.2‰. The δD1 value ranges from −191‰ to −148‰, δD2 value ranges from −165‰ to −115‰, and δD3 value ranges from −153‰ to −107‰. Methane and its homologues (C2-4) become more enriched in 13C and D as the carbon number increases (δ13C1 < δ13C2 < δ13C3 < δ13C4, δD1 < δD2 < δD3); the aforementioned is consistent with the carbon and hydrogen isotopic characteristics of thermogenic gases. The thermal maturity RO of the natural gas from the Xujiahe Formation in the Yuanba area ranges 1.09%–1.78%, whereas the RO value of the natural gas from the Xujiahe Formation in other areas of central Sichuan ranges 0.64%–0.92%. The natural gas from the Xujiahe Formation in central Sichuan is mainly from the coal measure source rocks of the Xujiahe Formation. The gas from the 2nd Member of the Xujiahe Formation (Xu-2 Member) in the Yuanba area is mixed gas; it is a mixture of the high-mature coal-derived gas from the coal measure source rock of the Xujiahe Formation and the oil-cracked gas from the Lower Cambrian (and Lower Silurian). The δD value of methane from the Xujiahe Formation in the Sichuan Basin is relatively high as it is higher than −200‰. Compared to the coal-derived gas from the source rocks formed in limnetic facies with freshwater in the Taibei Sag, Turpan-Hami Basin, though at similar thermal evolution stage, the difference of the δD values of methane can be as high as 90‰, indicating that the source rock of the Xujiahe Formation is formed in an environment with water salinization.

Pore structures and fractal characteristics of nano-pores in shale of Lucaogou formation from Junggar Basin during water pressure-controlled artificial pyrolysis

To analyse the pore structures and fractal characteristics of nano-pores during OM evolution, a series artificial hydrous pyrolysis experiments were conducted on shale samples at 250℃∼500℃ under 50 MPa water pressure. Low-pressure N2 adsorption was performed to investigate the pore structure and fractal dimension of pores on pyrolysis residues. Based on the model by Frenkel-Halsey-Hill, the fractal dimensions of D (relative pressure P/Po from 0 to 1), D1 (before P/Po = 0.5) and D2 (after P/Po = 0.5) were calculated. With the simulation temperature increasing, the pyrolysis products presented three stages that corresponded with the lower maturity (< 350℃), maturity (350℃∼400℃) and higher maturity (400℃∼500℃) stages. For pore structures, Type IV isotherms and Type H3 hysteresis loops occurred in the shale samples, and the adsorbed nitrogen quantity presented an increasing tendency. By analysing the relationship between the pore volume, surface area, and average diameter with OM evolution, pores also occurred during a stage of no change and increased and increased sharply, all of which corresponded to the thermal evolution stages. In the fractal dimension, the relationships between D, D1, D2 and the simulation temperature showed that shale heterogeneity was associated with the OM evolution stage. The rand-size relatio hip between D1 and D2 at different thermocatalytic stages suggested that the main influencing factors on the adsorption of shale gas were the micro-, meso-pores and the quantities of micropores. Therefore, through the research on pore structure and the fractal dimension of pyrolysis residues, we could determine the developmental characteristics of pores and the changing situation of shale heterogeneity based on the migration, preservation, and accumulation of generated hydrocarbons during OM evolution. This research provides a theoretical foundation for the exploration and exploitation of shale gas.

Gas generation potential and processes of Athabasca oil sand bitumen from gold tube pyrolysis experiments

Gold-tube pyrolysis experiments were conducted on two oil sand bitumens (OSBs) from the top and bottom of the McMurray Formation in the Athabasca oil sand region of Alberta, Canada. Temperatures ranging from 300 °C to 650 °C and a pressure of 50 MPa with heating rates of 2 °C/h were used to investigate the gas generation behavior of OSB. The extractable residual bitumen content decreased systematically with increasing heating temperatures resulting in a continuous increase in total hydrocarbon gas yields with the highest value of about 480 mg/g bitumen at 650 °C. Among hydrocarbon gases, the yields of methane (C1) increased consistently with experimental temperatures, while the yields of ethane (C2), propane (C3), butanes (i + n-C4) and pentanes (i + n-C5) increased initially to a critical pyrolysis temperature and then decreased at higher temperatures. Molecular indices (C1/C2, C2/C3, C2/i-C4, C3/C4, i-C4/n-C4, i-C5/n-C5 and C1/ΣC1-5) obtained in this work are different from typical primary thermogenic gases generated from kerogen or secondary thermogenic gases derived from thermal cracking of oil. Three stages of OSB thermal evolution were identified over a wide range of heating temperatures. The first stage (300–425 °C) reflects initial decomposition of thermally unstable moieties in resins and asphaltenes. Gas generated at this stage was dominated by carbon dioxide and hydrogen sulfide with minor amounts of hydrocarbon. Hydrocarbon gases were enriched in wet gas components with increasing heating temperatures. The second stage (425–525 °C) corresponds to liquid oil cracking and wet gas generation. While the yields of methane and ethane still increased with heating temperatures, yield of propane reached a maximum and yields of butane and pentane started to decline. The third stage (525–650 °C) reflects wet gas cracking and dry gas generation as indicated by the dramatic decrease of wet gas components and increase in gas dryness. Variations of gas yields and chemical compositions from two OSBs were partially caused by different levels of biodegradation. The top OSB has experienced less biodegradation influence than the bottom one as indicated by higher saturated and aromatic hydrocarbon contents and intact alkylphenanthrene distribution. Increased biodegradation of OSB yielded a higher concentration of polar compounds and an overall lower hydrogen content, which reduced the hydrocarbon gas generation potential. Slightly higher amounts of wet gas components were generated from the top OSB because of the relatively higher content of reactive moieties (mainly alkyl groups) at a lower biodegradation level, while a higher proportion of methane was observed from the bottom, severely biodegraded OSB that was enriched in cross linked ring structures.

Distribution and source significance of 2-methylalkanes in coal-measure source rocks, northwest China

GC-MS analysis was conducted on 59 coal-measure source rock (CSR) samples in the study area. Between nC14 and nC38, a series of 2-methylalkanes were detected. The 2-methylalkanes distribution can be summarized into 3 distribution modes: Front peak-type, Middle peak-type and Behind peak-type distribution. The same distribution mode is distributed at different maturity stages, and there are different distribution modes at the same thermal evolution stages, indicating that the distribution was slightly influenced by thermal evolution. C27C28C29 regular sterane triangulation is a template which is commonly used to judge the source of organic matter and sedimentary environment. But it is not applicable to judgment of the source of organic matter of coal-measure source rock (CSR) as higher plants are the basic substance. The organic matter constitution in CSR is still complicated, we need to know secondary organic matter in CSR except for plant so as to analyze the sedimentation and diagenetic environment. Within C17C22C28 2-methylalkanes (iC17-iC22-iC28) triangulation, samples with Front peak-type distribution of 2-methylalkanes are distributed near the 2-methylalkane C17 (iC17) end member. Samples with Middle peak-type distribution are distributed near the 2-methylalkane C22 (iC22) end member. Samples with Behind peak-type distribution are distributed near the 2-methylalkane C28 (iC28) end member. In combination with distribution characteristics of isoprenoid alkenes and biomarker compounds, different regions in the iC17-iC22-iC28 triangulation can be divided into different sources of organic matter and sedimentary environment. Based on this, the iC17-iC22-iC28 triangulation used to judge the parent material organic matter of CSR was established. In comparison with C27C28C29 regular sterane triangulation, it is more effective to judge the source of organic matter in CSR with iC17-iC22-iC28 triangulation.