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The characteristics of biomarker compounds and their occurrence states in different layers of the Permian Fengcheng Formation shale in Mahu Sag, Junggar Basin are poorly understood. By using experimental techniques such as rock pyrolysis, gas chromatography-mass spectrometry, fluorescence thin sections, and argon ion polishing electron microscopy, the material basis of hydrocarbon source rocks in different intervals, the distribution characteristics and significance of biomarker compounds, and different occurrence states of shale oil are clarified. This is of great significance for the next step in exploration and deployment in the Mahu Sag. The shale of the Fengcheng Formation in the Mahu Sag is mainly medium to good hydrocarbon source rocks, with type Ⅱ organic matter and in a mature evolutionary stage. The composition characteristics of biomarker compounds show high abundance of Pr and Ph, β-carotane, and C29 rearranged steranes. The C27-C28-C29 regular steranes exhibit an inverted "L" distribution, indicating that the organic matter is mainly contributed by lower aquatic organisms such as algae. Lower Pr/Ph ratios and higher gammacerane indices reflect a saline reducing sedimentary environment. Maturity parameters such as C31αβ22S/(22S+22R), C29M/C29H, and C29ββ/(ββ+αα) for hopanes and steranes indicate that the hydrocarbon source rocks are in the mature stage. In addition, the shale of the second member of the Fengcheng Formation has greater hydrocarbon generation potential and better source rock material basis than that in the first and third members. Meanwhile, biomarker compound parameters such as C20/C23TT, C21/C23TT, and Ga/C30H indicate that the second member has more contributions from algae and other organisms, and a more reducing and saline environment. The hydrocarbons in the second member are mainly in a free occurrence state, residing in intergranular and intragranular pores. The study shows that the second member of the Fengcheng Formation is more favorable for shale oil enrichment and preservation, showing a better prospect for shale oil exploration and development.

Based on the latest results of near-source exploration in the Middle and Lower Jurassic of the Tuha Basin, a new understanding of the source rocks, reservoir conditions, and source-reservoir-cap rock combinations of the Jurassic Shuixigou Group in the Taibei Sag is established using the concept of the whole petroleum system, and the coal-measure whole petroleum system is analyzed thoroughly. The results are obtained in three aspects. First, the coal-measure source rocks of the Badaowan Formation and Xishanyao Formation and the argillaceous source rocks of the Sangonghe Formation in the Shuixigou Group exhibit the characteristics of long-term hydrocarbon generation, multiple hydrocarbon generation peaks, and simultaneous oil and gas generation, providing sufficient oil and gas sources for the whole petroleum system in the Jurassic coal-bearing basin. Second, multi-phase shallow braided river delta–shallow lacustrine deposits contribute multiple types of reservoirs, e.g. sandstone, tight sandstone, shale and coal rock, in slope and depression areas, providing effective storage space for the petroleum reservoir formation in coal-measure strata. Third, three phases of hydrocarbon charging and structural evolution, as well as effective configuration of multiple types of reservoirs, result in the sequential accumulation of conventional-unconventional hydrocarbons. From high structural positions to depression, there are conventional structural and structural-lithological reservoirs far from the source, low-saturation structural-lithological reservoirs near the source, and tight sandstone gas, coal rock gas and shale oil accumulations within the source. Typically, the tight sandstone gas and coal rock gas are the key options for further exploration, and the shale oil and gas in the depression area is worth of more attention. The new understanding of the whole petroleum system in the coal measures could further enrich and improve the geological theory of the whole petroleum system, and provide new ideas for the overall exploration of oil and gas resources in the Tuha Basin.

As an important biological element, nitrogen is causally linked with organic matter accumulation, but a systematic and regular understanding has not been developed. This paper discusses this issue by taking the widely developed Permian-Paleogene terrestrial (lacustrine) hydrocarbon source rocks in China as an example. The results show that the terrestrial source rocks in China can be classified into three groups according to the nitrogen isotope (δ15N) compositions and combined with the salinity and evaporative alkali mineral characteristics: the circum-neutral group 1 (average δ15N=4.0‰±1.5‰), the circum-neutral group 2 (average δ15N=7.1‰±1.6‰), and the alkaline group (average δ15N=18.4‰±3.3‰). In the circum-neutral group with δ15N < 10‰, the δ15N of the source rocks is positively correlated with organic matter abundance, type, hydrocarbon generating capacity and shale oil potential due to the fact that higher δ15N characterizes changes in the composition of the hydrocarbon generating bio-precursors. In the alkaline group with δ15N>10‰, the organic matter types are good and shale oil potentials are higher, but the response relationship between δ15N of source rocks and organic matter accumulation is not as good as that of the circum-neutral group, reflecting that the organic matter accumulation in alkaline group is influenced by other comprehensive factors other than δ15N. Accordingly, the organic matter accumulation models of three types of lacustrine source rocks (< 5‰, 5‰-10‰, and >10‰) classified on the basis of δ15N were established. The δ15N has the potential to trace organic matter accumulation and quality of source rocks. For example, low δ15N type (δ15N < 5‰) is of poor quality and medium-high δ15N type (δ15N>5‰) is of good qualityin lacustrine source rocks. This paper enriches the biogeochemical and hydrocarbon source rock geochemical studies of nitrogen by exploring organic matter accumulation in source rocks from the new perspective of nitrogen isotope composition and nitrogen cycling.

Oil sources and accumulations in complex oil reservoirs of superimposed basins are difficult to identify and recover because of multiple kitchens and multistage charging processes. Constraining the oil sources and characterizing their accumulation patterns is a critical challenge. In this study, 46 crude oils from the Upper Wuerhe Formation, a widely distributed oil reservoir in the Mahu Sag of the Junggar Basin, NW China, are geochemically characterized to assess their sources and spatial distribution. These oils are divided into four groups: group I oils (characterized by high β-carotane and gammacerane concentrations, low C 21 /C 23 and (C 19 + C 20 )/C 23 tricyclic terpane ratios, and low Pr/Ph ratios); group II oils (characterized by low β-carotane and gammacerane concentrations, high C 21 /C 23 and (C 19 + C 20 )/C 23 tricyclic terpane ratios, and moderate Pr/Ph ratios); group III oils (very high Pr/Ph ratio (>3), the lowest β-carotane and gammacerane concentrations, and low tricyclic terpane concentration, but relatively high C 19 and C 20 tricyclic terpane abundance); and group IV oils (refered to here as geochemically hybrid, and inferred to be sourced from mixed P 1 f and C/P 1 j source rocks). The integration of oil-source correlation and geological framework indicates that oils generated from multiple kitchens are more likely to be near-sourced accumulations, providing a plausible example for oil accumulation in a complex oil reservoir of superimposed basin with several sets of kitchens and multistage oil charging history. The results show that multisource and multistage hydrocarbon accumulation is a common characteristic of prolific superimposed basins. The oil accumulation pattern must be established by carefully characterizing sources and charging processes to reduce the risk of exploration activities.

Abstract The effective production of shale oil is important for the cost‐effectiveness in the oil and gas industry. Oil price volatility and uncertainty require suitable hydraulic fracturing schemes to maximize production and to minimize fracturing costs. Since the reduction of fracture stage saves bridge plugs and fracturing costs, it is considered as a possible method to improve the cost‐effectiveness. To maintain the stimulated reservoir volume, cluster numbers per stage are consequently increased, which may induce nonuniform fracture propagation and interference which affects the stimulation efficiency. This study conducts a comparative study for single‐stage (reduced) and two‐stage (not reduced) fracturing schemes with the same fracturing fluid volume. Reservoir geomechanics and rock mechanics analyses are conducted for Jimsar shale oil in north‐western China with a single‐stage multicluster fracturing model established. Fracture geometries and key factors are investigated followed by the evaluation of the fractured well production. The relationship between multicluster parameters and production is quantified. Meanwhile, two‐stage fracturing modeling is also set up to compare with single‐stage fracturing modeling. Fracturing results show that although single‐stage fracturing results in nonuniform fracture propagation, the overall stimulation is satisfactory. Production results show that the nonuniform growth of fracture clusters leads to different contributions to the production from individual clusters and the production from inner fractures is significantly inhibited. Compared with two‐stage fracturing with the same pumping volume, it is found out that single‐stage fracturing can lead to cost‐effective horizontal well production in Jimsar shale oil given certain values of hydraulic fracturing costs, and the reduced stage scheme is preferable in low oil price and high uncertainty scenarios.

β-Carbolines are potentially strong alkaloids with a wide range of bioactivities, and their dimers exhibit stronger antitumor activity other than the monomers. However, the detailed mechanisms of the β-carboline dimers in inhibiting sarcoma (SARC) remain unclear. The results showed that β-carboline-3-carboxylic acid dimers Comp1 and Comp2, which were synthesized in our lab and modified at the N9 position and linked at the C3 position, exhibited effective inhibition activity on MG-63 proliferation (IC50 = 4.6μM). Meanwhile, the large scale transcriptome profiles of SARC from The Cancer Genome Atlas (TCGA) were analyzed, and found that abnormal expression of genes relevant to apoptosis, cell cycle, and signaling pathways of Hedgehog, HIF, Ras involved in the SARC pathogenesis. Interestingly, both dimers could promote the apoptosis and arrest the cell cycle in S phase to inhibit proliferation of MG-63. Moreover, Comp1 and Comp2 inhibited the expression CDK2, CCNA2, DBF4, and PLK1 associated with various immune cells and cell cycle in MG-63. Remarkably, drug-target interaction network analysis showed that numerous proteins involved in cell cycle were the potential targets of Comp1 and Comp2, especially CCNA2. Further molecular docking, isothermal titration calorimetry (ITC) and Cellular Thermal Shift Assay (CETSA) confirmed that both dimers could directly interact with CCNA2, which is significantly correlated with CD4+ T cells, by strong hydrophobic interactions (Kd=5.821 ×106 N). Meanwhile, the levels of CCNA2 and CDK2 were inhibited to decrease in MG-63 by both dimer treatments at transcription and protein levels, implying that Comp1 and Comp2 blocked the interaction between CCNA2 and CDK2 through competitive binding with CCNA2 to arrest the cell cycle of MG-63 cells in the S phase. Additionally, the transcriptome profiles of β-carboline-treated mice from Gene Expression Omnibus (GEO) were obtained, and found that similar antitumor mechanism was shared among β-carboline derivatives. Overall, our results elucidated the antitumor mechanisms of Comp1 and Comp2 through dual-suppressing the function of CCNA2 to profoundly arrest cell cycle of MG-63, then effectively inhibited cell proliferation of MG-63. These results provide new insights into the antitumor mechanism of β-carboline dimers and new routes of various novel cancer-related drug targets for future possible cancer therapy.

The Permian Fengcheng Formation in the Mahu sag of the Junggar Basin is a crude oil reservoir and source rock. However, its stratigraphic characteristics, the boundary marks of the three members (lower, middle, and upper), and the sediment-filling processes are unclear. This study presents the sedimentary systems and sediment-filling processes in an intracontinental rift basin of this area using sedimentary-faces analysis, sequence stratigraphy, well logs, and two-dimensional seismic interpretations. The results show that the Fengcheng Formation consists of three third-order sequence stratigraphy (SQf1, SQf2, and SQf3). The lowest member of the Fengcheng Formation is composed of gray to dark gray thin middle layers of tuff, lacustrine dolomitic mudstone, and argillaceous dolomite near the depocenter. Tuff, siltstone, a small amount of fan–delta glutenite, volcanic breccia, and basalt are present near the fault zone. The logging curve is characterized by a high gamma-ray (GR) value, high amplitude, wavelength growth, and medium frequency. Near the depocenter, the middle member of the Fengcheng Formation comprises gray and gray–black thin layers of lacustrine muddy dolomite and dolomitic mudstone and thin sandstone and mudstone interbedded between tuff and gravel near the orogenic belt. The logging curve displays high-to-low GR values, high amplitude, short wavelength, and high frequency. The upper member of the Fengcheng Formation is not characterized by lesser tuffaceous and dolomitic components but by an increased fan–delta sandy content. Next, the bottom of the upper member is composed of lacustrine mudstone and siltstone interbedded between dolomitic mudstones; whereas, the top of the upper member is dominated by fan–delta coarse sandstone and sandy conglomerate. The logging curve shows low GR values, small amplitude, and continuous stability. The sediment-filling process of the Fengcheng Formation is controlled by fault activity. Overall, the lower and middle members of the Fengcheng Formation expand during the sediment-filling process of the lake basin of the Mahu sag; whereas, the upper member contracts. The strong uplift of the Horst near the Baiquan and Mahu orogenic belts led to an increase in provenance supply, resulting in a contraction of the southwestern margin of the lake basin during the sedimentation period from lower member to upper member of Fengcheng Formation.

By using the latest geological, seismic, drilling and logging data, this article studies the basic conditions for the formation of the total petroleum system and the orderly coexisting characteristics and accumulation models of conventional & unconventional reservoirs in the Lower Permian Fengcheng Formation in the Junggar Basin. Controlled by thermal evolution, hydrocarbon generation and expulsion process of the high-quality source rocks in alkaline lake as well as the characteristics of multi-type reservoirs (conglomerate, sandstone, dolomite and shale), conventional structure-lithologic reservoirs and tight oil and shale oil reservoirs controlled by source-reservoir structure have been formed. On the plane, mature conventional reservoirs, medium-high mature tight oil, and medium-high mature shale oil reservoirs coexist orderly from the slope area around Mahu sag to the sag. Based on the orderly coexisting characteristics of conventional and unconventional reservoirs in the Fengcheng Formation, it is clear that oil and gas in the Fengcheng Formation accumulate continuously over a large area in three accumulation models: integrated source-reservoir, source-reservoir in close contact, and separated source-reservoir model. The three accumulation models differ in relationship between source-reservoir structure, reservoir lithology and spatial distribution, hydrocarbon migration, oil and gas type. It is pointed out that the conventional & unconventional oil and gas should be explored and developed as a whole to achieve an overall breakthrough of the total petroleum system. This study is expected to enrich the geological theory of oil and gas enrichment in continental basins and to provide an analogy for exploration and research in other hydrocarbon-rich sags.

The characteristics and main controls of continental shale oil reservoirs in the Permian Lucaogou Formation in the Jimsar Sag of Junggar Basin were studied based on seismic, core and logging data. Oil was found in a large area in the Lucaogou Formation, mainly in micro and nano pore throats or bedding fractures in free or adsorbed states. There are two sweet spot layers separated by mudstones. The formation pressure and maturity of shale reservoirs gradually decrease from the sag area to the slope area, while the crude oil density gradually increases. The quality and maturity of source rocks controlled the distribution and properties of shale oil. The sedimentary microfacies controlled the distribution of shale oil. The lithology and physical properties of shale controlled the enrichment of shale oil. Hydrocarbon generation pressurization was the main driving force for shale oil accumulation.

In order to reveal the shale oil production mechanism and production efficiency under the energy-depleted development mode, experiments on expulsion oil based on imbibition and elastic energy release under high temperature and pressure were carried out, and nuclear magnetic resonance on-line monitoring was used to observe the production characteristics of shale oil. The experimental results show that the imbibition-expulsion oil mainly occurs in the small-size pore-throat system. Under the condition of high temperature and pressure, the oil-expulsion efficiency is generally less than 2% affected by pore pressure, which is significantly different from the conventional imbibition experiment results. Although elastic-energy expulsion oil occurs in different sizes of pore-throat systems, the oil-expulsion efficiency in large size pore-throat systems is more sensitive to temperature. Overall, the total elastic-energy oil-expulsion efficiency is significantly positively correlated with reservoir physical properties, production differential pressure and temperature, and negatively correlated with crude oil viscosity. Comprehensively considering various geological factors affecting oil-expulsion efficiency, the shale oil production efficiency evaluation model under the energy-depleted development mode is constructed, and the movable oil porosity of shale oil development section in the study area is evaluated. The results show that there is a good positive correlation between movable oil porosity and oil production intensity. The movable oil porosity of dry layer is generally lower than 0.5% and that of poor oil layer is between 0.5% and 1.5%. When the movable oil porosity is between 1.5 and 2.5%, it can be determined as the type II oil layer, and for more than 2.5%, it is the type I oil layer. The single-well evaluation results show that the shale oil “sweet spots” of the Lucaogou Formation in Jimsar Sag are mainly distributed in P2l22−1∼ P2l22−3 and P2l12−1∼ P2l12−3, which is in good agreement with the current development status.

The Junggar Basin is rich in natural gas resources, but it has hardly been explored, with the proven rate being less than 9.0%. Although the hinterland of the Junggar Basin has a favorable condition for natural gas accumulation, the complex gas sources cause great trouble in the selection of zones and belts for exploration. Based on the molecular composition and stable carbon and hydrogen isotope data of 95 natural gas samples from 72 wells in this area, combined with the characteristics of structural evolution history, burial history, hydrocarbon generation and expulsion history, and fluid inclusions, this paper clarified the geneses and sources of natural gas, identified the secondary alteration of natural gas, and restored the process of natural gas accumulation. Natural gas in the hinterland was divided into four types: Type I was oil-type gas from the Lower Permian Fengcheng Formation; Type II was coal-type gas derived from the Carboniferous source rock; Type III was the mixture of Type I and II gases, which constituted the major fraction of natural gases in the hinterland; and Type IV that referred to secondary microbial gas formed by the biodegradation of crude oil. During the Late Cretaceous, the Carboniferous and Fengcheng source rocks entered the gas generation peak and a series of natural gas reservoirs were formed. However, affected by the later tectonic movements, some gas reservoirs were damaged or adjusted, and natural gas leakage and biodegradation occurred. This study has shifted the focus of natural gas exploration in the study area from the petroleum system associated with the Middle Permian source rocks to that with the Lower Permian and Carboniferous source rocks, which is of great significance for natural gas exploration in the Junggar Basin. Further, it provides an example to identify the geneses and sources of natural gas under complex conditions based on integrated geological and geochemical assessments.

The Mahu Sag in the Junggar Basin, China, is a hydrocarbon-rich sag. Abundant hydrocarbon source rocks were developed in the late Paleozoic there across the Carboniferous–Permian boundary. However, studies of the source rocks have focused mainly on the lower Permian Fengcheng Formation. Here we compare the Fengcheng Formation with other Carboniferous rocks and those of the lower Permian Jiamuhe and middle Permian Lower-Wuerhe formations. Based on organic petrological and geochemical data, the organic matter precursors, sedimentary facies, and resource potential of these source rocks were investigated. The bio-precursors of Carboniferous, Jiamuhe, and Lower-Wuerhe Formations were dominantly estuarine higher plants, Nematothallus -higher plants, and spores, respectively. The bio-precursors of Fengcheng Formation were mainly bacteria and algae, and the organic matter is abundant, with a high hydrocarbon-generating capacity and significant shale oil potential. In contrast, the other three formations contain poor-quality source rocks, although the Lower-Wuerhe Formation has a higher organic matter abundance than the Jiamuhe Formation. The Carboniferous organic matter contains mainly type II kerogen, whereas the Jiamuhe and Lower-Wuerhe formations contain type III kerogen. The thermal maturities determined from T max values is larger than those indicated by biomarkers. The biomarkers show that the three studied formations contain a mixture of terrestrial higher plants and bacteria–algae, with the contribution of green algae being higher than that of bacteria in most samples. However, the ratio of algae to bacteria is lower than that of the Fengcheng Formation. The Fengcheng Formation was deposited in a strongly reducing, high-salinity, and water-stratified sedimentary environment. The other three formations were deposited in an oxidizing–reducing, low-salinity, and water-unstratified environment. They are characterized by the predominance of mudstone over carbonate rocks and the descending distribution type of tricyclic terpenes. Our results provide a basis for research on upper Paleozoic source rocks in western China, and useful information for oil and gas exploration in the Mahu Sag.

Well Gaotan 1 was tested a high yield oil and gas flow of more than 1 000 m3 a day in the Cretaceous Qingshuihe Formation, marking a major breakthrough in the lower assemblage of the southern margin of Junggar Basin. The lower assemblage in the southern margin of the Junggar Basin has favorable geological conditions for forming large Petroleum fields, including: (1) Multiple sets of source rocks, of which the Jurassic and Permian are the main source rocks, with a large source kitchen. (2) Multiple sets of effective reservoirs, namely Cretaceous Qingshuihe Formation, Jurassic Toutunhe Formation and the Khalza Formation etc. (3) Regional thick mudstone caprock of Cretaceous Tugulu Group, generally with abnormally high pressure and good sealing ability. (4) Giant structural traps and litho-stratigraphic traps are developed. The northern slope also has the conditions for large-scale litho-stratigraphic traps. (5) Static elements such as source rocks, reservoirs and caprocks are well matched, and the dynamic evolution is suitable for large oil and gas accumulation. The lower assemblage of the southern margin of the Junggar Basin has three favorable exploration directions, the Sikeshu Sag in the west part, the large structures in the middle and eastern part, and the northern slope. Key Words: southern margin of Junggar Basin, Well Gaotan 1, lower assemblage, accumulation condition, exploration direction

Microbial methanogenesis from crude oil is an important source of CH4 for gas reservoirs and atmospheric greenhouse gases. However, its petrological records have not been found in natural environments, and the geological conditions under which it may occur remain unclear. Here, we provide the first petrological evidence of Fe(III)-mediated methanogenic hydrocarbon degradation in a deep subsurface oil reservoir in Northwest China. The major findings are as follows: (1) highly positive δ13C values (up to +16‰) of secondary calcite attributed to methanogenesis; (2) paragenetic relation of high-δ13C calcite to biodegraded hydrocarbon; and (3) remarkably high FeO contents (up to 8 wt%) and heavy δ56Fe ratios (up to +0.52‰) in calcite, indicative of microbial Fe(III) reduction. Our study shows that methanogenic hydrocarbon degradation can occur in Fe(III)-reducing environments. This process transformed hydrocarbons into CO2 and CH4, where the former mostly precipitated as Fe-rich calcite (the carbon sink), while the latter, representing an estimated ~1968 Tg, might have escaped into the overburden and atmosphere from the Permian reservoir during the Late Triassic to Early Jurassic, which may have acted as an important CH4 source in changing global climate in the geological past. [ABSTRACT FROM AUTHOR]

Methane (CH4) is an important greenhouse gas, but its behavior and influencing factors over geological time scales are not sufficiently clear. This study investigated the Late Paleozoic Ice Age (LPIA), which is thought to have experienced an interval of rapid warming at ca. 304 Ma, that may have been analogous to modern warming. To explore possible causes of this warming event, we investigated ancient alkaline lakes in the Junggar Basin, northwestern China. Results show that microbial CH4 cycling here was strong, as evidenced by carbonate d13C (d13Ccarb) values of >5‰, ~+0.6‰ offsets between pristane d13C (d13CPr) and phytane d13C (d13CPh) values, a 3ß-methylhopane index of 9.5% ± 3.0%, and highly negative d13C values of hopanes (-44‰ to -61‰). Low sulfate concentrations in the alkaline lakes made methanogenic archaea more competitive than sulfate-reducing bacteria, and the elevated levels of dissolved inorganic carbon promoted methanogenesis. Biogenic CH4 emissions from alkaline lakes, in addition to CO2, may have contributed to rapid climate warming. [ABSTRACT FROM AUTHOR]

Shale oil is becoming increasingly important in the global energy market, but its accumulation mechanism is not fully understood. We present novel and direct fluid inclusion data from the Lower Permian Fengcheng Formation, Mahu Sag, Junggar Basin, northwest China. Shortite veins in this source rock contain abundant two-phase gas-liquid hydrocarbon inclusions and coeval aqueous inclusions. The inclusions have highly variable degrees of bubble filling (5-80 vol% vapor) and homogenization temperature differences between oil and aqueous inclusions (-50 °C), which demonstrate that fluid (oil-gas-water) immiscibility occurred at high pressures. The hydrocarbon inclusions record different levels of fluid overpressure (32.9--43.0 MPa), with a paleopressure coefficient of 1.3--1.7. Episodic fluid overpressure release resulted in shale oil accumulation, with faults/fractures acting as important migration pathways. Oil from deeper and more mature source rocks within the Fengcheng Formation was expelled upward to the shale oil reservoir. These processes are common and important in shale oil systems. These results show that the accumulation of unconventional hydrocarbons occurs pervasively within the reservoirs, and fluid displacement is critical in exploration and exploitation. [ABSTRACT FROM AUTHOR]

The linkages between nitrogen cycling, nitrogen isotopes, and environmental properties are fundamental for reconstructing nitrogen biogeochemistry. While the impact of ocean redox changes on nitrogen isotopes is relatively well understood, it is poorly known how nitrogen responds to changes in pH and salinity. To fill the knowledge gap, we explore the effects of these environmental parameters using a well-controlled set of samples from Carboniferous-Paleogene lake sediments in China. Our results show that the threshold of 10-12‰ in d15N works to distinguish alkaline (pH > 9) from circum-neutral conditions. Elevated Mo levels in the alkaline samples support the idea of NH3 volatilization from a reducing water column in an alkaline setting. For non-alkaline lakes, d15N values tend to be higher (up to +10‰) in more saline, anoxic settings, which is attributed to either the expansion of stagnant anoxic waters spurring water-column denitrification or a shift from plant-based toward more microbially dominated ecosystems or both. Our results imply that salinity-induced redox stratification and basicity can alter nitrogen biogeochemical cycling beyond what is shown by the marine nitrogen isotope record alone. This finding will result in an improved understanding of the dynamic controls of d15N in sediments and lead to better biogeochemical interpretations of paleo-environmental conditions from unknown environmental settings on Earth and beyond Earth. [ABSTRACT FROM AUTHOR]

Sodium carbonate evaporites can provide important paleoclimatic constraints and economic resources but are relatively rare; most known examples are limited to the Cenozoic. The first known late Paleozoic occurrence was recently reported from the Fengcheng Formation in the northwestern Junggar Basin, NW China. However, its mineralogy, age, and geologic setting have been sparsely documented. To help establish a broader understanding of the formation of these important deposits, this paper presents a comprehensive new data set that includes drill core, well logs, petrographic analyses, X-ray diffraction data, organic geochemistry (biomarkers), and U-Pb zircon age data. Evaporite deposition is estimated to have occurred between ca. 305 Ma and 296 Ma in a series of extensional grabens that hosted a stratified, hypersaline lake (or lakes). The lake deposits are closely associated with coeval volcanic rocks, suggesting that subsurface interaction of these with CO2-enriched hydrothermal fluids may have contributed to the excess alkalinity required to precipitate Na-carbonate. Trona (NaHCO3 · Na2CO3 · 2H2O) in the Fengcheng Formation was likely formed syndepositionally and then partly replaced by wegscheiderite (Na2CO3 · 3NaHCO3). Other evaporite minerals most likely formed during diagenesis. The Fengcheng Formation also contains nahcolite (NaHCO3), which requires pCO2 >680 ppm to form, although no textural evidence was found to demonstrate a primary origin. The presence of extensive lacustrine evaporites nonetheless reflects a relatively warm and arid climate at ~40-50°N that apparently coincided with the late Paleozoic icehouse. [ABSTRACT FROM AUTHOR]