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[Display omitted] • Taiyang, Jiaoshiba and Weirong shale gases show 12‰ variation in δ2H of methane. • Carbon isotopic reversal occurs in Taiyang, Jiaoshiba and Weirong shale gases. • Hydrogen isotopic reversal only occurs in Taiyang and Jiaoshiba shale gases. • Gas δ2H is greatly affected by water salinity, causing delay of isotope change. Sichuan Basin is important commercial shale gas producing basin in China, where shale gas explorations were mainly targeted at the Upper Ordovician Wufeng-Lower Silurian Longmaxi formations with burial depth mostly of 2000 ∼ 3500 m. This study performed a detailed investigation about the δ2H features of shale gases from the Wufeng-Longmaxi shale with burial depth of <2250 m (Taiyang), 2250 ∼ 3500 m (Jiaoshiba) and >3500 m (Weirong). The average δ2H 1 and δ2H 2 values are of −135‰ and −146‰, −137‰ and −157‰, −137‰ and −124‰, respectively in Taiyang, Jiaoshiba and Weirong shale gas fields. The average δ2H 1 values are nearly the same in the three gas fields, while average δ13C 1 values increase from −35.2‰ to −28.5‰ as from Weirong to Taiyang. When wetness >8%, δ2H 1 values increase with decreasing wetness rapidly implying dominant influences from maturity, when wetness <8%, the δ2H 1 variation is small and mainly in the range of (−140 ± 15)‰, indicating a strong influence from cogenetic water. All gases are characterized by a trend of δ13C 1 > δ13C 2 > δ13C 3 , and gases in Taiyang and Jiaoshiba are characterized by δ2H 1 > δ2H 2 , while gases in Weirong are dominated by δ2H 1 < δ2H 2. Generally, with decreasing gas wetness, ethane first become more enriched in D and 13C, then become more depleted in D and 13C, and finally become more enriched in D and 13C again. The turning point of wetness from rollover to post-rollover zones is 1.2% for the δ13C 2 while 0.8% for the δ2H 2. Such delay in δ2H 2 also indicates the strong influences from the cogenetic water medium. [ABSTRACT FROM AUTHOR]

Recent studies on both conventional (thermogenic gas) and unconventional (shale gas) gases show comparable carbon/hydrogen isotope rollover, i.e., before the rollover point, carbon/hydrogen isotope increases with increasing thermal maturity (or decreasing gas wetness), while after the rollover point, the gas component (i.e., ethane, propane, etc.) becomes more depleted in 13 C or 2 H with increasing thermal maturity. In order to further investigate potential mechanism of the isotope rollover, combined with previous researches on isotope rollover, this study carried out two batches of pyrolysis experiments on a low mature coal sample from the Songliao Basin, China at constant temperatures for about 72 h under the condition with added water and without added water. The results demonstrate that carbon and hydrogen isotope rollover of ethane and propane started at 500 °C, no matter with added water or without added water. Combined with previous studies on gases of various origins, it is found that such isotopic anomalies were a common phenomenon at high thermal mature stage, despite of what kind of the source rocks and whether adding water or not under the laboratory condition. This is likely caused by the mixing of gases directly from the decomposition of macromolecule of kerogen and those from the tightly entrapped straight-chain species in kerogen at relatively high thermal mature stage. These straight-chain species are normally entrapped in the kerogen, and will probably be released at high thermal maturation stage. Marine facies source rocks from southern China also demonstrate the existence of such tightly entrapped hydrocarbons at very high thermal maturity. The results may have important significance on the gas exploration at relatively high mature stage and have a guidance on the gas production changes during the exploration. [ABSTRACT FROM AUTHOR]

This study performed a detailed geochemical analyses of the components, stable carbon isotopes of alkane gas and CO 2 , stable hydrogen isotopes of alkane gas and helium isotopes of reproducing gas from the largest tight gas field (Sulige) and shale gas (Fuling) field in China. The comparative study shows that tight gas from the Sulige gas field in the Ordos Basin is of coal-derived origin, which is characterized by a positive carbon and hydrogen isotopic distribution pattern (δ 13 C 1 > δ 13 C 2 > δ 13 C 3 > δ 13 C 4 ; δ 2 H 1 > δ 2 H 2 > δ 2 H 3 ), i.e., the carbon and hydrogen isotopes increase with increasing carbon numbers. Carbon dioxide from this field are of biogenic origin and the helium is crust-derived. Shale gas from the Fuling shale gas field belongs to oil-derived gas which has complete carbon and hydrogen isotopic reversal of secondary alteration origin (δ 13 C 1 < δ 13 C 2 < δ 13 C 3 ; δ 2 H 1 < δ 2 H 2 < δ 2 H 3 ), i.e., the carbon and hydrogen isotopes decrease with increasing carbon numbers. Such complete isotopic reversal distribution pattern is due to the secondary alteration like oil or gas cracking, diffusion and so on under high temperature. In that case, positive carbon or hydrogen isotopic distribution pattern will change into complete isotopic reversal as the temperature increases. Carbon dioxide is of abiogenic origin resulting from the thermal metamorphism of carbonates and helium is crust-derived. [ABSTRACT FROM AUTHOR]

Abstract: The compound specific hydrogen and carbon stable isotope ratios of alkanes in natural gases from the Xujiahe and Jurassic formations in the western Sichuan Basin were investigated to distinguish between coal-derived and oil-associated gases. All gases were determined to be coal-derived and sourced from the Xujiahe Formation. Thermal maturities of the source rocks are expected to vary from 0.8–1.8% vitrinite reflectance (%R o) according to the empirical relationship between the measured δ13CCH4 values and % R o, which is within the scope of the maturities of source rocks (0.7–2.1%). In particular, C1–3 alkanes of primary coal-derived gases which have not undergone any secondary alteration become more enriched in deuterium with increasing molecular mass and the δDCH4 values increase with increasing thermal maturity of source rocks. In the Sichuan Basin, δD values of coal-derived gases sourced from terrigenous source rocks of the Xujiahe Formation are more negative than those of oil-associated gases sourced from marine organic matter of the Sinian, Permian and Triassic formations. [Copyright &y& Elsevier]

Abstract: Based on quantum chemistry calculations for normal octane homolytic cracking, a kinetic hydrogen isotope fractionation model for methane, ethane, and propane formation is proposed. The activation energy differences between D-substitute and non-substituted methane, ethane, and propane are 318.6, 281.7, and 280.2cal/mol, respectively. In order to determine the effect of the entropy contribution for hydrogen isotopic substitution, a transition state for ethane bond rupture was determined based on density function theory (DFT) calculations. The kinetic isotope effect (KIE) associated with bond rupture in D and H substituted ethane results in a frequency factor ratio of 1.07. Based on the proposed mathematical model of hydrogen isotope fractionation, one can potentially quantify natural gas thermal maturity from measured hydrogen isotope values. Calculated gas maturity values determined by the proposed mathematical model using δD values in ethane from several basins in the world are in close agreement with similar predictions based on the δ13C composition of ethane. However, gas maturity values calculated from field data of methane and propane using both hydrogen and carbon kinetic isotopic models do not agree as closely. It is possible that δD values in methane may be affected by microbial mixing and that propane values might be more susceptible to hydrogen exchange with water or to analytical errors. Although the model used in this study is quite preliminary, the results demonstrate that kinetic isotope fractionation effects in hydrogen may be useful in quantitative models of natural gas generation, and that δD values in ethane might be more suitable for modeling than comparable values in methane and propane. [Copyright &y& Elsevier]

Abstract: Values of δ 11B reported in the literature for Holocene samples of the same foraminiferal species show large variability (6‰) relative to cited precision (<1‰). This is indicative of significant inter-laboratory biases and raises concerns about the accuracy of foraminiferal proxy pH records. To investigate this problem we have measured the δ 11B of modern ocean carbonates using several different analytical procedures. We have used total evaporation negative thermal ionisation mass spectrometry (TE-NTIMS), with various sample preparation and loading procedures and multi-collector inductively coupled plasma mass spectrometry (MC-ICPMS). The δ 11B of pure boric acid solutions measured by TE-NTIMS and MC-ICPMS agree well, demonstrating no fundamental biases between the techniques. Yet the δ 11B values measured by TE-NTIMS for non-foraminiferal carbonates are about 2‰ lighter than those by MC-ICPMS whereas foraminifers measured by the same standard TE-NTIMS procedure are 2 to 6‰ heavier than those by MC-ICPMS. Significantly, we found that foraminiferal samples kept in acidic solution over several months yielded lower δ 11B values (up to 5‰ lower) and better reproducibility when re-measured by TE-NTIMS. We infer that organic material, released on foraminiferal dissolution, causes biases in NTIMS measurements. No residual organics should be present in the MC-ICPMS measurements as matrix is separated from sample before analysis. Moreover we demonstrate by standard addition the absence of any matrix influence in the MC-ICPMS procedure beyond the inherent uncertainties in the standard addition approach (∼±0.35‰ 2sigma). Degradation of the inferred organic residue, either by long term storage in acidic solution or by loading samples in 30% H2O2, reduces but does not totally remove the (variable) bias between TE-NTIMS and MC-ICPMS δ 11B measurements. Despite these problems, careful analysis of similar samples by NTIMS may permit data to be obtained with consistent relative differences that still yield valuable proxy records, but there is clearly considerable potential for inaccuracies to result in such an approach from hard to detect changes in matrix. [Copyright &y& Elsevier]

Abstract: The Upper Triassic Xujiahe Formation in the Sichuan Basin, SW China consists of a series of coal measures. The first, third and fifth members of this formation are dominated by gas prone dark mudstones and coals. The mudstones contain Type II and III kerogens with average organic carbon contents around 1.96%. These source rocks are mature in the central Sichuan and highly mature in the western Sichuan Basin, characterized by gas generation with subordinate amounts of light oil or condensate oils. The source rocks are intercalated with the sandstone dominated second, fourth and sixth members of the Xujiahe Formation, thus leading to three separate self contained petroleum systems in the region. The proven gas reserves in the Xujiahe Formation are only less than that of the Triassic Feixianguan Formation and the Xujiahe Formation has the second largest gas field (Guang’an gas field) in the basin. Gases derived from the Xujiahe Formation coals generally show a normal stable carbon isotopic trend for C1–C4 n-alkanes, with the highest δ 13C2 values among the nine gas pay zones in the basin (−20.7‰ to −28.3‰), and δ 13C1 values as low as −43.0‰ in the central Sichuan. Gas accumulations with an oil leg have also been found in the eastern and southern Sichuan where the thickness of the Xujiahe Formation is significantly reduced. Gases in these accumulations tend to show low δ 13C2 values (−30.0‰ to −36.3‰), characteristic of oil prone source rocks. [Copyright &y& Elsevier]

Oilfield water contains valuable information on the origin, migration, and geochemical evolution of fluids in sedimentary basins. Jiuquan Basin is one of the richest oil basins in China and holds large potential for future tight oil exploration. We use a wide range of geochemical and isotopic tracers to evaluate the origin and reconstruct the migration of oilfield water across Jiuquan Basin, including major (Ca, Mg, Na, K, NH 4 , Cl, SO 4 , Br, HCO 3) and minor (B, Li, Ba, Sr, Rb) elements, water isotopes (δ18O, δ2H), the isotopes of carbon (δ13C-DIC), boron, (δ11B), and strontium (87Sr/86Sr). We show that the oilfield water was co-generated with the original hydrocarbons in the deep Qingxi sub-basin in the western part of the basin, and were derived from blending of two distinctive sources (1) deep-source brine that originated from relicts of evaporated seawater; and (2) geothermal water that underwent intensive water-rock interactions with the Lower Cretaceous Xiagou Formation, characterized by high DIC, Li+ , B, and SO 4 concentrations and distinctive δ18O, δ13C-DIC, and 87Sr/86Sr, which are consistent with the composition of the source rocks of Xiagou Formation. The distinctive geothermal signature was detected in the Yaerxia oilfield water in the eastern side of the Qingxi sub-basin, suggesting eastward co-migration of the geothermal water and crude oil to the shallow geological trap. Further eastward migration of the saline formation water into less saline environment in the central (Laojunmiao) and eastern (Shiyougou) fields caused base-exchange reactions, adsorption, and sulfate reduction that resulted in a progressive reduction in the overall salinity, Na+, NH 4 +, Li+, B, SO 4 2−, and 87Sr/86Sr, coupled with increasing Ca2+, Mg2+, Sr2+, and δ11B. Later dilution of Laojunmiao oil field caused B desorption, oxidation of organic matter, and secondary methanogenesis. The integration of multiple geochemical tracers provides systematic geochemical criteria's for reconstructing the origin and evolution of the oilfield water in Jiuquan Basin and the ability to distinguish between the original composition and secondary modification of the geochemistry of the oilfield water. • Reconstruction of the origin of oilfield water from Jiuquan Basin, China. • Geochemical evidence for geothermal water origin in the western Jiuquan Basin. • Data suggest eastward migration of the oilfield water across the basin. • Water-rock interactions along fluids migration modified the original composition. • Distinction between salinization and freshening process of oil field water. [ABSTRACT FROM AUTHOR]

Pyrolysis experiments were conducted at 370–550 °C for 72 h in closed gold capsules to investigate the effect of nickel and magnetite on gas generation from coal in the absence and presence of water. Nickel had a great catalytic effect on the yield, molecular and carbon and hydrogen isotope composition of generated gases. The methane yields increased significantly while heavy hydrocarbon gas yields decreased substantially due to the catalysis of nickel both in the absence and presence of water. The nickel catalysis caused an increase of δ 13 C CH4 value in the absence of water and a decrease of δ 13 C CH4 value in the presence of water. Results of molecular and carbon isotopic composition of hydrocarbons indicate that nickel could catalyze the decomposition of high-molecular-weight organic matter and Fischer-Tropsch-type (FTT) reactions both of which were responsible for the increased methane yield. FTT reactions catalyzed by transition metals are an important pathway for methane generation, especially in the presence of water. The catalytic decomposition of organic matter and FTT reactions also caused an increase of δ 2 H CH4 value both in the presence and absence of water. CO 2 yield and 13 C CO2 value increased obviously in the presence of nickel due to the catalytic decomposition of organic matter. In experiments without added water, addition of magnetite enhanced CO 2 yield at all temperatures but only enhanced methane yield slightly at high temperature (430–550 °C). The increased CO 2 and methane yields can be attributed to the oxidative decomposition of long-chain hydrocarbons via redox reactions between magnetite and hydrocarbons. In experiments with added water, addition of magnetite only caused a slight increase of methane and CO 2 yields at 500 °C and 550 °C but did not influence their yields at 370–450 °C, indicating that water inhibited the effect of magnetite on methane and CO 2 generation at low temperature. The addition of magnetite did not have systematic influence on carbon and hydrogen isotopes of hydrocarbon gases and carbon isotopes of CO 2 . Generally, the influence of magnetite on gas generation was very small. [ABSTRACT FROM AUTHOR]

With the increasing number of shale gas wells being hydraulically fractured with recycled flowback and produced water to reduce the consumption of fresh water, geochemical indicators of hydraulic fracturing flowback fluids (HFFFs) from such wells need to be found to evaluate the potential pollutants caused by shale gas development. To fill this knowledge gap, we analysed 64 HFFF samples from 3 Changning wells (fracked with recycled wastewater) to form a time series and compared them to HFFF samples from 3 Weiyuan wells (fracked with fresh water). We also made comparisons of HFFFs from two types of wells in the Appalachian Basin with reported data. The results indicated that regardless of the fracturing fluid being used, the water‒rock reaction caused by the hydraulic fracturing process resulted in the release of exchangeable phase elements, such as lithium, boron, with relatively depleted δ7Li and δ 11B, and strontium with relatively enriched 87Sr/86Sr values on the shale surface, into the HFFFs. The composition of the injected fracturing fluid affected the strength of the water‒rock reaction, but the effect is negligible, as the fracturing process can still form the unique Sr, Li, and B isotope ratios of the HFFF. Thus, the elemental signatures (B/Cl and Sr/Cl) and isotopic fingerprints (δ 11B, δ7Li, and 87Sr/86Sr) derived from HFFFs can be used to distinguish between HFFFs from wells hydraulically fractured by either fresh water or recycled wastewater and flowback water from conventional oil and gas wells. The results are important for the environmental evaluation of the large number of wells being fracked with recycled wastewater each year. [Display omitted] • δ 11B and 87Sr/86Sr can be used as indicator for HFFF in Changning field. • Hydraulic fracturing caused the release of minerals enriched in 10B, 6Li, and 87Sr. • Shale formation water composition determined the ratio between Na, Ca, Cl, and Br. • Fracturing fluid composition impact the major elements of HFFFs in the first dozens of days. [ABSTRACT FROM AUTHOR]

Although the annual production of shale gas in China was 13 × 10 8 m 3 in 2014, a systematic study on geochemical and isotopic characteristics of these unconventional gases has not been well addressed. In the present study, almost all shale gas samples available in China, including marine shale gas from the Wufeng-Longmaxi Formation in the Sichuan Basin (O 3 w–S 1 l) and terrestrial shale gas from Chang 7 Member (T 3 y 7 ) in the Ordos Basin, were collected and analyzed for their geochemical and isotopic compositions. The shale gas from the Wufeng-Longmaxi Shale is dry gas with an average methane content of 98.38% and records a highest content of CH 4 in the world (99.59%), which is consistent with the very high thermal maturity levels of the gas shales that have equivalent vitrinite reflectance (EqVRo) values between 2.4 and 3.6%. The δ 13 C 1 values are correspondingly heavy and record a heaviest δ 13 C 1 values (−26.7‰) for the shale gases found in the world as well. The average values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 for the Wufeng-Longmaxi shale gas are −31.3‰, −35.6‰, and −47.2‰, respectively, displaying a complete carbon isotopic reversal (i.e., δ 13 C 1 > δ 13 C 2 > δ 13 C 3 ). δ 2 H CH4 and δ 2 H C2H6 has an average value of −148‰ and −173‰, respectively, also yielding a hydrogen isotopic reversal (i.e., δ 2 H CH4 > δ 2 H C2H6 ). The Chang 7 shale has an average TOC content of 13.81% with vitrinite reflectance (VRo) values between 0.7 and 1.2%. The Chang 7 shale gas is wet gas with an average methane content of 84.90% and is rich in heavy gaseous hydrocarbons (C 2 –C 5 ). The respective values of δ 13 C 1 , δ 13 C 2 and δ 13 C 3 are −48.7‰, −36.4‰ and −31.3‰, displaying a positive carbon isotopic distribution pattern (i.e., δ 13 C 1 < δ 13 C 2 < δ 13 C 3 ). The average δ 2 H CH4 , δ 2 H C2H6 and δ 2 H C3H8 values are −256‰, −244‰ and −188‰, respectively, and are characterized by a positive distribution pattern (i.e., δ 2 H CH4 < δ 2 H C2H6 < δ 2 H C3H8 ). The differences in gas wetness and carbon and hydrogen isotopic distribution patterns between the shale gases from the Wufeng-Longmaxi and Chang 7 shale are attributed to variations in thermal maturity levels. CO 2 is present in low content in both the Wufeng-Longmaxi and Chang 7 shale gases, mostly less than 1%. δ 13 C values for the CO 2 in the Wufeng-Longmaxi Formation are between 8.9 and −9.2‰, indicating an inorganic origin from the cracking of carbonate mineral in the shales under high temperatures. In contrast, δ 13 C values of the CO 2 in the Chang 7 shale gas range from −8.2 to −22.7‰, indicating an organic origin from the thermal degradation of organic matter. Helium in both the Wufeng-Longmaxi and Chang 7 shale gases is dominantly of curst origin in terms of their R/Ra ratios that vary from 0.01 to 0.08. Positive carbon isotopic distribution pattern is typical of primitive thermogenic gas. However, it can be converted into complete or partial carbon isotopic reversal patterns due to secondary alteration. The causes that yield carbon isotopic reversal include (1) mixing of gases with the same source but different thermal maturity levels; (2) secondary cracking of oil or wet gas; (3) formation water-involved reactions; (4) gas diffusion; and (5) carbon isotope exchange between alkane gases at high temperature. Among them, carbon isotopic exchange between alkane gases at high temperature is a key factor. Nine plots have been drawn based on the shale gases from China, USA and Canada. Among them, the plot of δ 13 C 2 versus wetness demonstrates a “lying-S” shape with two inflection points on the gas wetness axis. The wetness value of 1.4% represents a critical point from pyrolytic gas (primary cracking gas) to cracking gas (secondary cracking gas) and whereas the wetness value of 6% marks the end of oil generation. On the diagram of wetness versus δ 13 C, shale gases with wetness values greater than 1.6% are characterized by positive carbon isotopic distribution pattern, whereas a complete or partial carbon isotopic reversals are observed for shale gases with wetness values less than 1.6%. [ABSTRACT FROM AUTHOR]

Abstract: Compound-specific carbon and hydrogen isotopic compositions of three natural gas round robins were calibrated by ten laboratories carrying out more than 800 measurements including both on-line and off-line methods. Two-point calibrations were performed with international measurement standards for hydrogen isotope ratios (VSMOW and SLAP) and carbon isotope ratios (NBS 19 and L-SVEC CO2). The consensus δ 13C values and uncertainties were derived from the Maximum Likelihood Estimation (MLE) based on off-line measurements; the consensus δ 2H values and uncertainties were derived from MLE of both off-line and on-line measurements, taking the bias of on-line measurements into account. The calibrated consensus values in ‰ relative to VSMOW and VPDB are: NG1 (coal-related gas): Methane: δ 2HVSMOW =−185.1‰±1.2‰, δ 13CVPDB =−34.18‰±0.10‰ Ethane: δ 2HVSMOW =−156.3‰±1.8‰, δ 13CVPDB =−24.66‰±0.11‰ Propane: δ 2HVSMOW =−143.6‰±3.3‰, δ 13CVPDB =−22.21‰±0.11‰ i-Butane: δ 13CVPDB =−21.62‰±0.12‰ n-Butane: δ 13CVPDB =−21.74‰±0.13‰ CO2: δ 13CVPDB =−5.00‰±0.12‰ NG2 (biogas): Methane: δ 2HVSMOW =−237.0‰±1.2‰, δ 13CVPDB =−68.89‰±0.12‰ NG3 (oil-related gas): Methane: δ 2HVSMOW =−167.6‰±1.0‰, δ 13CVPDB =−43.61‰±0.09‰ Ethane: δ 2HVSMOW =−164.1‰±2.4‰, δ 13CVPDB =−40.24‰±0.10‰ Propane: δ 2HVSMOW =−138.4‰±3.0‰, δ 13CVPDB =−33.79‰±0.09‰ All of the assigned values are traceable to the international carbon isotope standard of VPDB and hydrogen isotope standard of VSMOW. [Copyright &y& Elsevier]

Organic-rich mudrocks that served as sources for the prolific unconventional system of the Bakken Formation display pronounced heterogeneity in composition and expulsion behavior. The dominant mudrocks of the Bakken Formation (tarls) contain few biogenic allochems and have a diagenetic history dominated by compaction. Mudrocks that at deposition contained relatively more siliceous biogenic debris display microquartz cement that reduced porosity and enhanced rock stiffness. Against a background of strong expulsion at the formation scale, the ratio of methane to iso-butane (C 1 / i C 4) in gas extracted from these organic-rich mudrocks reveals a wide range of expulsion efficiency. C 1 / i C 4 in crushed rock gas is strongly controlled by maturity, with lower maturity samples displaying a range of iso-butane content, but little methane. At higher maturity a strong negative correlation between methane and iso-butane is interpreted in terms of expulsion efficiency, with higher proportional amounts of iso-butane corresponding to greater oil expulsion. The majority of mudrocks in the Upper and Lower Bakken Formation source rocks display strong expulsion efficiency, although a minority of samples display relatively high oil retention. A key control on the degree of petroleum expulsion in the Upper and Lower members that have served as sources for the Middle Bakken reservoir is the extent of cementation by authigenic microquartz. The grain assemblages in the organic-rich mudrocks are mixed, but are mostly dominated by grains of extrabasinal derivation (tarls). At the time of deposition only a minority of the mudrocks contained a substantial component of grains of intrabasinal derivation, notably radiolarians, which reacted to form authigenic microquartz. The higher-maturity mudrocks cemented by microquartz display relatively high retention of generated hydrocarbons whereas the associated tarls show a wide range of expulsion behavior. The contrast in expulsion state displayed across Bakken Formation mudrocks suggests that compaction, where not inhibited by cementation, persists into the oil window and acts together with overpressuring as a driver of hydrocarbon expulsion. Where cemented early in the diagenetic history, mudrocks cease to compact and are able to retain more of their generated oil. These results for the Bakken Formation have implications for unconventional systems more generally. The cementation status of mudrocks may be one of the key factors for predicting expulsion efficiency and for determining the efficacy of organic-rich mudrocks as hydrocarbon sources (where compaction-dominated) versus reservoirs (where cemented early in the burial history). • Early microquartz cementation in Bakken Formation source rocks arises from alteration of opaline skeletal debris. • Strong hydrocarbon expulsion occurs in most of the source rocks, excepting those with significant cementation. • Early cementation locally creates stiff rocks that resist post-cementation compaction. [ABSTRACT FROM AUTHOR]

• Reuse flowback water for hydraulic fracturing reduces the blue water footprint of shale gas development. • Reuse of flowback water for hydraulic fracturing could reduce the shale gas production. • Hydraulic fracturing with saline water changes the water salinity and chemistry of flowback water. • Tradeoff between reduction in fresh water utilization and shale gas productivity. The increased water consumption for hydraulic fracturing and the volume of wastewater generated from shale gas and tight oil exploration are major environmental challenges associated with unconventional energy development. Recycling of the flowback and produced water for hydraulic fracturing is one of the solutions for reducing the water footprint of hydraulic fracturing and removing highly saline oil and gas wastewater. Here we investigated the implications of recycling saline wastewater for hydraulic fracturing by monitoring the natural gas production, flowback water volume, and the water quality of generated flowback water in shale gas wells from Changning gas field in Sichuan Basin, China. A comparison of two sets of shale gas wells, with six wells in each sub-group, from the same location in Changning gas field shows lower (~20%) natural gas production and higher flowback water volume (~18%) in wells that were fracked with recycled saline wastewater relative to wells that were fracked with fresh water after a year of production. Geochemical analysis suggests that hydraulic fracturing with saline wastewater increases the salinity of the wastewater and reduces the magnitude of water-shale rock interactions. In spite of the direct economic consequences in reduction in natural gas production from recycling of wastewater for hydraulic fracturing, in areas where water scarcity could become a limiting factor for future large-scale shale gas development, hydraulic fracturing with recycled flowback water can be more beneficial than utilization of limited freshwater resources, as long as the higher saline flowback water is fully recycled. [ABSTRACT FROM AUTHOR]

Transition metal catalysis has been advocated as a critical mechanism for natural gas generation. But its presence and significance in geological settings have long been debated due to conflicting results of laboratory experiments and the lack of reliable field indicator. In this study, a low rank coal sample from the Shahezi Formation of the Songliao Basin was subjected to nonhydrous pyrolysis with and without transition metal. The chemical and isotopic compositions of gaseous products in experiments were analyzed to investigate the mechanism and potential indicator of transition metal catalysis in sedimentary basins. The chemical and carbon isotopic compositions of hydrocarbon gases generated in pyrolysis experiments revealed that transition metal could catalyze both decomposition of organic matters and methane synthesis such as Fischer-Tropsch Type reactions during maturation of source rocks under experimental conditions resembling geological settings. Catalytic methane has uniform δD values unrelated to source rock maturity, which is helpful in identification of catalytic natural gases in sedimentary basins. Transition metal catalysis is probably not a common mechanism for natural gas generation in sedimentary basins due to the positive correlation between δD CH4 of natural gases and maturities of source rocks observed in most natural cases. However, transition metal catalysis could well interpret the restricted range of δD CH4 and carbon isotopic reversal phenomenon of natural gases in the Yingcheng Formation of the Xujiaweizi fault-depression whose origin has long been debated. So we inferred that the transition metal catalysis may have occurred in deep strata of the Xujiaweizi fault-depression and played a significant role in natural gas generation. Our study revealed that restricted range of δD CH4 of natural gases with different maturities may serve as an effective indicator of transition metal catalysis in sedimentary basins. It provides a new perspective to investigate the significance and universality of transition metal catalysis in different geological settings. • Transition metal could catalyze decomposition of organic matter. • Transition metal could catalyze abiogenic methane synthesis. • Transition metal catalysis may have occurred in the Xujiaweizi fault-depression. • The restricted range of δD CH4 is an effective indicator of transition metal catalysis. [ABSTRACT FROM AUTHOR]