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The mercury isotope signatures of coalbed gas and oil-type gas: Implications for the origins of the gases
Applied Geochemistry 109 (2019) 104415
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The mercury isotope signatures of coalbed gas and oil-type gas: Implications for the origins of the gases
T
Shunlin Tanga,∗, Yuping Zhoua, Xiaojie Yaoa, Xinbin Fengb,∗∗, Zhaopeng Lia, Gaoen Wua, Zhu Guangyouc a
Institute of Resources and Environment, Henan Polytechnic University, Jiaozuo, Henan province, 454000, China State Key Laboratory of Environmental Geochemistry, Institute of Geochemistry, Chinese Academy of Sciences, Guiyang, 550081, China c Department of Petroleum Geology, Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China b
ARTICLE INFO
ABSTRACT
Editorial handling by Dr C S Eckley
The concentration of mercury vapor (elemental mercury, Hg0) in natural gases has been used to differentiate between coalbed gas and oil-type gas. However, the concentrations of Hg0 in coalbed gas and oil-type gas are highly variable, and its use as a genetic indicator is problematic. Here, for the first time, we report significant differences in the mass-dependent fractionation (MDF, measured with δ202Hg) and the mass-independent fractionation (MIF, measured with Δ199Hg, Δ200Hg and Δ201Hg) of Hg0 isotopes between coalbed gas and oil-type gas. Coalbed gas has an extremely negative δ202Hg (−5.8‰ to −3.08‰) and negative Δ199Hg (−0.19‰ to −0.01‰) relative to the assumed source, which is Permian coal from the Henan Province, China. Oil-type gas is characterized by less negative δ202Hg (−3.08‰ to −0.77‰) and positive Δ199Hg (0.06‰–0.30‰) relative to its E2-3s source rocks in the Liaohe oilfield (dark mudstones: δ202Hg = −1.96‰ to −2.48‰, Δ199Hg = 0.09‰–0.17‰). This significant difference in the MIF can be used to distinguish between coalbed gas and oil-type gas. Notably, the Δ200Hg values of our samples are as high as 0.15‰. We suggest that significant Hg0 MDF might occur during the formation of coalbed gas, but not during the formation of oil-type gas. This study highlights the potential of Hg0 isotopes as proxies for the source of natural gases.
Keywords: Mercury Mercury isotopes Gas genesis Coalbed gas Oil-type gas
1. Introduction Knowledge of the origins of natural gases is practically and theoretically useful in the oil and gas exploration industries. For example, the efficiency of Chinese natural gas exploration was low prior to 1980, because exploration was guided only by traditional theories relevant to oil-type gases. The discovery of coalbed gas after 1980 has expanded the scope of natural gas exploration in China (Dai et al., 2010). A range of geochemical proxies have been used to characterize the generation and origins of the natural gases; these include stable carbon and nitrogen isotopes, noble gas isotopes, clumped isotopes, chemical compositions, microbial information, hydrochemistry, and thermal maturity (Schoell, 1980; Stolper et al., 2014a). In addition, it has been shown that the concentration of mercury vapor (elemental mercury, Hg0) in natural gases provides useful genetic information (Dai et al., 2010). Mercury (Hg) has a high affinity for organic matter and sulfides (Haitzer et al., 2002); it is released into hydrocarbon reservoirs by
∗
thermal reduction or decomposition of Hg compounds during burial and tectonism (Rojey, 1997; Peters et al., 2005). At ambient temperatures, Hg is soluble in liquid aliphatic hydrocarbons at concentrations of 1–3 μg/mL, which is much higher than its solubility in water (0.05 μg/ mL) (Wilhelm and Bloom, 2000). The dominant Hg species in natural gases is Hg0, which accounts for > 85% of the total Hg (Ezzeldin et al., 2016). Mercury in natural gas occurs at concentrations of 10–400 000 ng/m3, depending on the geological setting in which the natural gas is found (Bingham, 1990; Dai, 1992). The Hg0 concentrations in natural gases are typically several orders of magnitude higher than those in ambient air (Dai, 1992; Zettlitzer et al., 1997; Lang et al., 2012). Mercury in natural gas can damage the aluminum heat exchanger boxes used to separate ethane and heavy hydrocarbons from commercial gas, poison catalysts, and increase the health risks to field workers in natural gas treatment plants (EGAS, 2011; Ezzeldin et al., 2016). It has been proposed that the concentration of Hg0 reflects the origin of natural gas (Ozerova, 1983); Dai (1992) showed that Hg0 concentrations are typically greater than 700 ng/m3 in coalbed gases,
Corresponding author. Corresponding author. E-mail addresses: [email protected] (S. Tang), [email protected] (X. Feng).
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https://doi.org/10.1016/j.apgeochem.2019.104415 Received 13 June 2019; Received in revised form 15 August 2019; Accepted 30 August 2019 Available online 30 August 2019 0883-2927/ © 2019 Elsevier Ltd. All rights reserved.
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and less than 500 ng/m3 in oil-type gases. However, subsequent studies have shown a substantial overlap between the Hg0 concentrations of oil-type gas (4–142 000 ng/m3) and coalbed gas (200–3 000 000 ng/ m3) (Liu, 2013). In addition, Hg0 concentrations vary significantly within a single gas field. Therefore, the Hg0 concentration alone is an ambiguous proxy of the source of a natural gas. Mercury has seven natural stable isotopes (196Hg, 198Hg, 199Hg, 200 Hg, 201Hg, 202Hg and 204Hg), and their ratios might provide additional information on the genesis of natural gases. Mass-dependent fractionation (MDF, denoted by δ202Hg) and mass-independent fractionation (MIF, denoted by Δ199Hg, Δ200Hg and Δ201Hg) of Hg isotopes are observed in nature, with variations greater than 10‰ for δ202Hg, Δ199Hg, and Δ201Hg, and around 1‰ for Δ200Hg (Blum et al., 2014; Sun et al., 2019). Some degree of MDF is associated with most abiotic and biotic Hg transformations, while MIF is mainly associated with photochemical processes (Bergquist and Blum, 2007; Zheng and Hintelmann, 2009). The Hg isotopic ratios show promise as a method to distinguish between different sources of natural gases. Washburn et al. (2018) presented the first compilation of the Hg isotopic compositions of natural gas. These workers analyzed the Hg-removal catalyst units that contained Hg after natural gas production. The values of δ202Hg and Δ199Hg varied from −3.75‰ to −0.68‰ and −0.02‰ to 0.65‰, respectively. The results indicate that the Hg isotopic composition can be used as a proxy for natural gas Hg emissions in some gas fields. In natural gases, MDF of the Hg isotopes occurs during biogenic and thermogenic formation processes (Rojey, 1997). In contrast, while a small MIF signature (< 0.2‰) can be induced in natural gases by changes to Hg speciation in the absence of light (e.g., reduction or oxidation in the dark) (Zheng and Hintelmann, 2010), a significant MIF signature (> 0.2‰) requires photochemical reactions, which are unlikely to occur underground. Therefore, we hypothesize that natural gases with different origins might preserve the Hg isotope signature, and in particular the MIF signature, of their source materials. To test this hypothesis, we measured the Hg0 isotopic composition of coalbed gas and oil-type gas from three gas fields in China. The objectives are to: (1) understand Hg isotope fractionation during the formation of natural gases; (2) verify whether different natural gases have distinguishable Hg0 isotope compositions; and (3) establish a new proxy for the origin of natural gas that can be used in natural gas exploration.
gas-bearing coal seam located at 470–947 m depth. The gas-bearing coal seam has an average thickness of 7.8 m, and is part of the Permian Shanxi Formation (P1), which formed in a tidal flat to fluvial deltaic setting (Liu, 2010; Fu, 2005). The coalbed gas consists of > 99.5% methane, and is used as a commercial fuel without post-extraction processing. 2.2. Sampling and analysis of mercury concentrations The natural gas samples were taken from pipelines connected to wellheads at the field sites. The Hg0 was separated from the untreated natural gas samples using a sampler consisting of three-stage serial impingers (500 mL each, Environmental Supply Company, USA) (Fig. 2). The first impinger was empty, and was used to remove water vapor from the gas and maximize Hg0 trapping efficiency within the succeeding impingers. The second to fourth impingers were filled with 100 mL of a trapping solution containing 4% (w/v) KMnO4 and 10% H2SO4 (v/v), that trapped the Hg0 present in the natural gas. The combination of KMnO4 and H2SO4 in solution has been used to trap Hg0 in gases produced by volatilization of coal and soil samples using a step heating combustion procedure (Biswas et al., 2008; Lefticariu et al., 2011), and from flue gases (Tang et al., 2016, 2017). A fifth impinger was packed with ~100 mg allochroic silicagel to absorb any water vapor in the remaining gas, so that the gas volume could be measured accurately in a dry gas flow meter. The five impingers were connected by U-type borosilicate glass tubes fastened together with flexible iron clamps. Reagent blanks of the KMnO4 and H2SO4 solution and the main chemicals used in recovery and analysis were measured; all results were below 6 ng/L (Table S1). To prevent Hg0 sorption onto the walls of the sampling and connecting tubes and borosilicate impingers, the sampling device was flushed repeatedly with the untreated natural gas from the wellheads in the field before sampling. Then, the raw natural gas was released to the five impingers via a 5 m Teflon tube connected to the pressure gauge at the wellhead. The flow rate of the natural gas was adjusted to ~6 L/min, and the collection time was greater than 3 h. At least 1 m3 of natural gas of each sample was collected (except for three samples of 0.83–0.97 m3) to ensure sufficient Hg for the isotopic analysis. During the sampling, the trapping solution retained a brown color, indicating that an excess of KMnO4 was maintained. Immediately after sampling, the three trapping solutions were reduced using appropriate amounts of 0.5 mL NH2OH–HCl (30%, w/v) and transferred into a 250 mL pre-cleaned borosilicate glass bottle. To test the efficiency of Hg0 trapping, we used our sampling device in the laboratory to trap the Hg0 produced by 5 mL of a Hg standard solution (NIST SRM 3133) diluted to give Hg concentrations of 10 ng/ mL, 50 ng/mL, 100 ng/mL, 200 ng/mL and 400 ng/mL. The Hg standard solutions were diluted to 50 mL with 18.2 MΩ cm−1 water and pumped with a peristaltic pump (Longer Pump LEAD-2, Halma in China) at a flow rate of 0.25 mL/min through 50 mL SnCl2 (3%) solutions. Petroleum gas, from which the Hg had been removed using a 100 mL aqua regia prior to use, was used to purge the product Hg0 at a flow rate of ~6 L/min for at least 3 h. The trapping solutions from all three impingers were analyzed for Hg and the Hg isotopic ratios were measured in solutions with Hg concentrations greater than 1.0 ng/mL (Table 2S); this limit was chosen to match the sensitivity of the multicollector inductively coupled plasma mass spectrometry (MC-ICP-MS, Neptune Plus) technique. The test results show that 95.2%–99.5%, 0.8%–5.5% and 0.2%–0.9% of the Hg in the standard solutions were trapped by the first, second and third impingers, respectively (Table S2). The trapping solutions were analyzed using cold vapor atomic fluorescence spectroscopy (Brooks Rand Model III) at the Institute of Resources and Environment, Henan Polytechnic University. The Hg concentration in the natural gas was calculated from the sum of the masses of Hg in the three trapping solutions, divided by the total
2. Methods 2.1. Geological background Untreated natural gas samples were collected at the wellheads of gas wells within three gas fields (Fig. 1): (1) the Liaohe oilfield in the Liaohe Basin, northeastern China, which is one of China's most important oil and gas production areas; (2) the Zhongyuan oilfield in the Bohai Bay Basin, central China; and (3) the No.6 coal mine, Hebi coalfield, Henan Province, China. Natural gases from the Liaohe and Zhongyuan oilfields are thought to be of terrestrial origin, with source rocks deposited dominantly in lacustrine and fluvial deltas. Stratigraphically, the source rocks belong to the Eocene Shahejie Formation (E2-3s); they are organic-rich mudstones and shales that contain algae and ostracod fossils (Wang et al., 2012; Wu et al., 2013). Five hydrocarbon source rock samples (dark mudstones) were collected from outcrops of the Eocene Shahejie Formation (E2-3s) in the Liaohe Oilfield. The total mercury concentration and mercury isotopes were analyzed to characterize the source rock, because there are few data that describe the Hg isotope composition of pre-anthropogenic terrestrial sediments. The natural gases of the Liaohe and Zhongyuan oilfields were extracted from gas reservoirs at depths of 2600–3200 m (Zhu et al., 2013, 2014), and > 3000 m from the surface wellheads, respectively. Untreated coalbed gas from the Hebi coal mine was extracted from a 2
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Fig. 1. Structural maps and locations of sampling sites ( ). (a) Structural map of the Liaohe oilfield in the western sag of the Liaohe Basin, northeastern China (Huang et al., 2008). (b) Structural map of the Zhongyuan oilfield in the Bohai Bay Basin, central China (Internal data, no published). (c) Structural map of the Hebi coalfields of Henan province, China (Fu, G.Q., 2005, in Chinese).
Fig. 2. Schematic illustration of the sampling device. 1: Sampling outlet, 2: First impinger (empty); 3–5: Three impingers filled with KMnO4 (4%) + H2SO4 (10%) solutions; 6. Impinger filled with silica gel; 7. Dry gas flow meter.
volume of the sampled gas. The first, second, and third impingers trapped 76%–97%, 2.9%–21.5%, and 0.1%–8.3% of the Hg, respectively. The five samples of dark hydrocarbon source mudstone were milled
and sieved to 200 mesh. Appropriate amounts of the powdered solid samples were weighed into 45 mL centrifuge tubes, and digested using 10 mL of reverse aqua regia (HNO3: HCl = 3:1, v/v), selected to accommodate the high organic content of the samples. The centrifuge 3
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tubes containing the digested samples were shaken overnight and placed in a water bath. The water bath was kept at 50 °C for half an hour, then heated to 95 °C and held at that temperature for 2 h. After cooling to room temperature, the digested samples were filtered into new 45 mL centrifuge tubes using disposable syringes and syringedriven 0.45 μm PVDF filters (Millex, OD = 33 mm). The filtered digested samples were capped, labeled, and stored in a refrigerator prior to analysis for total Hg using Brooks Rand Model III.
proxy for the origin of natural gases. The Hg isotopic compositions of samples from all three trapping impingers were measured for four samples with high Hg concentrations (L-2016-4-15-3, L-2016-4-17-3, L-2016-4-17- and L-2016-5-21-3) (Table S6). The δ202Hg value measured in the sample from the first impinger was generally the lowest, and the greatest difference in the δ202Hg values among the three impingers for a single sample was 2.52‰. One reason for the difference among the impingers is that there is likely to be a small amount (< 15%) of Hg species other than Hg0 in natural gas, including particulate Hg and organic mercury (Ezzeldin et al., 2016). These species might not be reduced to Hg0 and trapped in the first solution, but might be reduced to Hg0 and trapped in the second or third solutions, with a consequent increase in Hg concentrations and changes to the isotopic composition. Alternatively, MDF might have occurred during Hg trapping, such that the lighter Hg isotopes were trapped preferentially within the first impinger. The Δ199Hg values of samples from the three impingers are identical, within analytical uncertainty, suggesting that MIF did not occur during the Hg trapping process. The lowest percentage of Hg trapped by the first impinger is 76%. Using this value, and the largest measured difference in δ202Hg values of 2.52‰ between the first and third impingers, the difference in δ202Hg between the total Hg and the Hg in the first impinger is < 0.60‰; this value is considered to be a maximum value for the systematic uncertainty related to differences between the impingers. Furthermore, > 95% of the Hg0 was trapped by the first impinger in most cases, and the Hg isotopic composition of solutions from the first impinger in the laboratory validation test were within the 2SD uncertainty of the accepted value for NIST SRM 3133 (Table S2). Therefore, the Hg isotopic composition of the solution from the first impinger was considered to represent the Hg0 isotopic composition of the natural gas (Table S7). The Hg isotopic compositions of the coalbed and oil-type gases are shown in Fig. 3 and Table S7. The Hg0 isotope compositions of the coalbed gas samples are significantly different from those of the oil-type gas. The coalbed gases from the Hebi coalfield have very negative δ202Hg (−5.89‰ to −3.08‰) and slightly negative Δ199Hg values (−0.19‰ to −0.01‰), with average values of −4.77‰ ± 0.87‰ (n = 7, 1SD) and −0.11‰ ± 0.06‰ (n = 7, 1SD), respectively. The oil-type dry gases of the Liaohe and Zhongyuan oilfields showed higher δ202Hg values (−3.03‰ to −0.77‰, average = −1.89‰ ± 0.66‰, n = 13, 1SD) than the coalbed gas samples, and positive Δ199Hg values (0.15‰–0.30‰, average = 0.20‰ ± 0.06‰, n = 13, 1SD). The oiltype wet gases of the Liaohe and Zhongyuan oilfields had similar δ202Hg (−3.08‰ to −1.39‰, average = −2.08‰ ± 0.63‰, n = 10, 1SD) and Δ199Hg (0.06‰–0.21‰, average = 0.13‰ ± 0.05‰, n = 10, 1SD) to oil-type dry gases from the two oilfields and a Hg isotope signature similar to that of the source rocks (Table S8: δ202Hg = −1.96‰ to −2.48‰, average = −2.26‰ ± 0.20‰; Δ199Hg = 0.09‰–0.17‰, average = 0.13‰ ± 0.03‰, n = 5, 1SD). Therefore, we can distinguish between coalbed gas and oil-type gas based on the significant difference of Hg0 MIF signature. Given the similarities, results from the dry and wet oil-type gas were combined and are referred to subsequently as oil-type gas. The difference of 2.8‰ between the average δ202Hg values of coalbed gas and oil-type gas is more than four times larger than the largest difference in δ202Hg values (0.60‰) that might have arisen from analytical artefacts, as discussed above. The linear correlation between Δ199Hg and Δ201Hg gives a value for Δ199Hg/Δ201Hg of 0.76 ± 0.02 (R2 = 0.78, Pearson's correlation coefficient = 0.88) for the coalbed gas samples and 1.17 ± 0.03 (R2 = 0.79, Pearson's correlation coefficient = 0.89) for the oil-type gas samples (Fig. 4). This indicates that additional sources of Hg, such as Hg in hydrothermal fluids, were present in the natural gases.
2.3. Mercury isotope analysis The Hg isotopes were analyzed in the trapping solutions from the first impinger, trapping solutions from the second and third impingers with Hg concentrations > 1.0 ng/mL, and the digests of the five mudstone samples. The trapping solutions were diluted to 1.0–2.0 ng/mL Hg using 18.2 MΩ cm−1 water. The Hg isotopic ratios were measured using a multi-collector inductively coupled plasma mass spectrometer (MC-ICP-MS, Neptune Plus) at the State Key Laboratory of Ore Deposit Geochemistry, Chinese Academy of Sciences, China, following the method described by Tang et al. (2017). The sensitivity of the response to 202Hg was 0.8–0.9 V per ng/mL of Hg. The signal for 202Hg in the blank solutions was always < 10 mV. The instrumental mass bias was corrected using a sample–standard bracketing method. The Hg concentrations and matrices of the bracketing standard (NIST SRM 3133) were matched to the sample solutions. Uncertainties, based on measurements of NIST SRM 3133, are provided in Table S3. The Hg isotope ratios are reported using the delta (δ) notation, to represent the per mil deviation of the samples from the bracketing standard (Blum and Bergquist, 2007): δXXXHg (‰) = [(XXXHg/198Hgsample)/(XXXHg/198HgNIST3133) 1] × 1000,
(1)
where xxx is the mass of the selected Hg isotopes (199–202). The MIF signature is reported using the capital delta notation (ΔxxxHg), which represents the deviation of the measured δxxxHg from the δxxxHg calculated for MDF using the relationship: ΔXXXHg (‰) = δXXXHg - βXXX × δ202Hg, 199
200
(2) 201
where β is 0.252 for Hg, 0.5024 for Hg and 0.752 for Hg, respectively (Blum and Bergquist, 2007). The analytical uncertainty was determined using repeated analyses of the UM-Almadén secondary Hg standard solution, which has a similar Hg concentration (1–2 ng/g Hg) to the unknowns, and an acid matrix. Average values of the 1 ng/g and 2 ng/g UM-Almadén standard solutions were −0.53‰ ± 0.10‰ (2SD, n = 13) and −0.51‰ ± 0.10‰ (2SD, n = 11) for δ202Hg, −0.03‰ ± 0.04‰ (2SD, n = 13) and −0.04‰ ± 0.04‰ (2SD, n = 11) for Δ199Hg, and −0.00‰ ± 0.04‰ (2SD, n = 13) and −0.00‰ ± 0.06‰ (2SD, n = 11) for Δ201Hg (Table S4). These values are consistent with previously reported values (Blum and Bergquist, 2007; Tang et al., 2017). The uncertainties reported for the Hg isotope ratios in this study correspond to the largest value of the external 2SD uncertainty derived from repeated measurements of the UM-Almadén standard and the 2SD uncertainty derived from two replicate analyses of the sample solutions. 3. Results The Hg0 concentrations in coalbed gas from the Hebi coalfield are 56–155 ng/m3 (average: 123 ± 3 5 ng/m3, n = 7, 1SD) (Table S5). These values are lower than those recorded for oil-type wet gas (31–467 ng/m3, average = 216 ± 127 ng/m3, n = 1 5, 1SD) from the Liaohe oilfield, and oil-type dry gas (31 626–108 408 ng/m3, average = 54 676 ± 23 980 ng/m3, n = 16, 1SD) from the Zhongyuan oilfield. These results are inconsistent with the conclusions of Dai et al. (2001), and indicate that Hg0 concentrations might not be a suitable 4
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Fig. 3. Plot of δ202Hg vs. Δ199Hg for coalbed gas, oil-type wet gas and dry gas. The ellipses show the mean (inner ellipse) and 95% confidence levels (outer ellipse) of the δ202Hg and Δ199Hg. Calculations performed using the OriginPro 2017C software.
4. Discussion
material, which might include coal, oil, and shales (Tissot and Welte, 1984), and is also affected by the thermal evolution of the parent materials. The formation of natural gas is thermally driven and Hg0 is highly volatile, so it is commonly believed that Hg0 in natural gas is affected by tectonic activity (Bingham, 1990; Dai, 1992). Tectonic activity provides heat to drive thermal processes and might also provide
4.1. Differences in the mercury concentrations of coalbed gas and oil-type gas The Hg0 in natural gas is sourced mainly from the gas source
Fig. 4. Plot of Δ201Hg vs. Δ199Hg for coalbed gas and oil-type wet and dry gas. The error bars show uncertainties at the 2SD level. The Δ199Hg/ Δ201Hg ratio (1SD) is different to one, which indicates that additional sources of Hg (e. g., hydrothermal fluids) contributed to the natural gases. Calculations performed using the OriginPro 2017C software.
5
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additional Hg carried by hydrothermal fluids, in regions where hydrothermal activity is frequent. The Hg0 concentrations of coalbed gas (56–155 ng/m3), oil-type wet gas (31–467 ng/m3) and oil-type dry gas (31 626–108 408 ng/m3) measured in the present study (Table S5) are generally consistent with the results of previous studies that reported levels of Hg0 in natural gas between 10 and 400 000 ng/m3 (Bingham, 1990; Han et al., 2013). Natural gas has become an important and rapidly growing source of energy globally, so these high Hg0 concentrations are worthy of attention. A previous study by Dai et al. (2001) documented the concentration of Hg0 in 102 coalbed gas samples from 32 coal fields and 242 oil-type gas samples from 29 oil-gas fields in China, and concluded that the typical Hg0 concentrations of coalbed gas and oil-type gas are > 700 ng/m3 and < 500 ng/m3, respectively. Based on these findings, they proposed that the concentration of Hg0 is a useful indicator of the origin of a natural gas. Our results are inconsistent with the conclusions of Dai et al., but consistent with the results of another recent study that did not find a difference in the concentrations of Hg0 between coalbed gas and oil-type gas in the Tarim basin, China (Liu, 2013). Natural variations in the gas to oil ratio can cause large variations in Hg0 concentrations (Ryzhov et al., 2003; Faramawy et al., 2009), and a continuous decrease in the Hg0 concentrations in natural gases was attributed to precipitation of Hg0 inside a pipeline between the wellhead and treatment facilities (Wilhelm and Bloom, 2000). Thus, the use of Hg0 concentration as an indicator of the origin of a natural gas is problematic.
coalbed gas formed by microbial decomposition of organic matter within the coal (Smith and Williams, 1984). Any Hg (II) bound to organic matter might be reduced to Hg0 during this process (Haitzer et al., 2002). Thermogenic coalbed gas generally forms from 150 °C to 220 °C, associated with the slow decomposition of organic material within the coal (Stolper et al., 2014b). As the organic materials decompose (e.g., through cracking of the kerogens), Hg0 and methane desorb from the organic material to form gases that diffuse slowly through the pores within the coal seams. The Hg0 and methane accumulate in the coal pores and are released when pressure decreases in response to uplift or erosion of the coal basin. To summarize, generation of biogenic and thermogenic coalbed gas is likely to involve biotic and abiotic processes (e.g., volatilization, diffusion, thermal reduction). Incomplete transformation of Hg during these processes would cause significant enrichment in the lighter Hg isotope in the product Hg0 within the coalbed gas (Kritee et al., 2007, 2008; Sun et al., 2013a, b; Koster Van Groos et al., 2014). In addition, if ~50% of the Hg in coalbed gas is from hydrothermal sources, as discussed above, then evaporation of Hg0 from the hydrothermal fluids might contribute to the lower δ202Hg in coalbed gas (Smith et al., 2005; Sherman et al., 2009). 4.3. Mercury isotope fractionation during the genesis of oil-type gas The wet and dry oil-type gases are enriched in the heavier and odd Hg isotopes relative to the coalbed gas, and can be distinguished from the coalbed gas, based on the significant difference in Δ199Hg (p < 0.01) and δ202Hg (Fig. 3). According to geological surveys, the sediment sources of the oil-type gases of this study are terrestrial dark mudstones and shales of the Eocene Shahejie Formation (E2-3s). The Hg isotope compositions of the dark mudstone samples (E2-3s) from the Liaohe oilfield are similar to those of the oil-type gases from the two oilfields (Table S8: δ202Hg = −1.96‰ to −2.48‰, average = −2.26‰ ± 0.20‰; Δ199Hg = 0.09‰–0.17‰, average = 0.13‰ ± 0.03‰, n = 5, 1SD). This indicates that the MIF signature observed in the oil-type gases is largely inherited from the source materials. In addition, our oil-type gas samples and the source mudstone samples all have positive Δ199Hg values, and these values are similar to those of lake sediments from pristine areas (Δ199Hg: +0.12 to +0.31‰, Yin et al., 2016). Notably, our samples also show slightly non-zero Δ200Hg values (up to 0.15‰); non-zero Δ200Hg values have previously been observed only in rain (Gratz et al., 2010; Chen et al., 2010; Demers et al., 2013; Enrico et al., 2016), freshwater fish (Bergquist and Blum, 2007), coastal sea water (Štrok et al., 2015), and black shales (Yin et al., 2017). The oil-type gases were generated from marine and terrestrial (lacustrine or fluvial) sediments enriched in organic matter. Sapropels and black shales in the oceans are typical marine source materials that generate oil gas (Tissot and Welte, 1984). Sapropels and black shales commonly show positive Δ199Hg values (Gehrke et al., 2009; Grasby et al., 2017; Yin et al., 2017; Wang et al., 2012). Therefore, Δ199Hg cannot be used alone as a proxy for the source sediment type. The Δ199Hg/Δ201Hg ratio of the analyzed oil-type gases is 1.17 ± 0.13, which is slightly different from the ratio generated by Hg (II) photoreduction (Fig. 4). This indicates that Hg from sources with a lower Δ199Hg was probably incorporated into the oil-type gas. The Liaohe and Zhongyuan oilfields are both cut by well-developed faults (Peng et al., 2019), so some of the Hg0 might be derived from deep fluids with near-zero Δ199Hg. We speculate that Δ199Hg values of the oil-type gas, if it had not been mixed with deeply sourced fluids, might have been more positive than our measured values. Furthermore, based on evidence from the literature and the new data presented here, we suggest that only marine or continental organic-rich sediments with positive Δ199Hg values are effective source rocks for oil or gas. However, further research is required to test this hypothesis. Previous workers have reported large variations in the δ202Hg
4.2. Mercury isotope fractionation during formation of coalbed gas Values of δ202Hg were plotted against Δ199Hg for the coalbed and oil-type gases (Fig. 3). Negative Δ199Hg values have been reported for coals worldwide (−0.11‰ ± 0.18‰ and coals from the Henan Province (−0.24‰ ± 0.09‰, n = 6, 1SD), the source of the coalbed gas in this study (Yin et al., 2014; Sun et al., 2014a). The Δ199Hg values of the coalbed gas analyzed in this study are negative (−0.11‰ ± 0.06‰, n = 7, 1SD), but less negative than those of the Henan coals. In addition, the Δ199Hg/Δ201Hg ratio of the coalbed gas is 0.76 ± 0.18 (Fig. 4), which is different to that measured for world coals (1.07 ± 0.04) and Henan coals (1.10 ± 0.06) (Yin et al., 2014; Zheng and Sun, 2016). The difference in slope indicates that the MIF signature of coalbed gas is not inherently unchanged from the source coal, but might reflect the presence of Hg with higher Δ199Hg in the coalbed gas. Previous studies have shown that geogenic processes do not impart a MIF signature (Δ199Hg ~ 0), based on the analysis of hydrothermal minerals in coals (Lefticariu et al., 2011; Sun et al., 2014b). Furthermore, positive MIF signatures in samples from the coalfields of the Shandong and Anhui provinces, China, and from Inner Mongolia, were interpreted as a record of hydrothermal Hg (Sun et al., 2014b; Zheng and Sun, 2016; Zheng et al., 2018; Peng et al., 2019). Therefore, we speculate that the coalbed gas contains a mixture of geogenic Hg from hydrothermal fluids with a near-zero or positive Δ199Hg and Hg derived from the coals. An isotope mixing model was used to show that the source coals and hydrothermal fluids contributed equal amounts of Hg to the coalbed gas, assuming that the source coals and hydrothermal fluids had Δ199Hg values of −0.24‰ and 0.00‰, respectively (Sun et al., 2014a). Therefore, we speculate that the Δ199Hg value of the Hebi coalbed gas is more negative than the measured values presented in this study. The Hebi coalbed gas had a much lower δ202Hg (−4.77‰ ± 0.87‰, n = 7, 1SD) than the world coal compilation (−1.16‰ ± 0.79‰) and coals from the Henan Province (−1.3‰ ± 0.7‰, n = 6) (Yin et al., 2014; Zheng and Sun, 2016) (Fig. 5), suggesting that there was significant MDF of Hg isotopes during the formation of coalbed gas. Further research is necessary to elucidate the details of the MDF, but it is possible to propose a hypothesis involving desorption and diffusion that explains some of the observations. During peatification and early coalification, biogenic 6
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Fig. 5. Plot of δ202Hg vs. Δ199Hg, showing results from coalbed gas and oil-type gas (this study), Permian coal from Henan province, China (Yin et al., 2014; Sun et al., 2014a), lake sediments from the Qinghai and Nam Co lakes of the Tibetan Plateau (Yin et al., 2016), and mudstones of the Eocene Shahejie Formation from the Liaohe oilfield (this study). The 95% confidence ellipse centered on the mean value was calculated using the OriginPro 2017C software.
values of pre-anthropogenic sediments and organic-rich lacustrine sediments far from sources of pollution (Yin et al., 2016, Fig. 5). For example, sediment profiles from the Qinghai and Nam Co lakes on the Tibetan Plateau have δ202Hg values from −5.04‰ to −2.16‰ (Yin et al., 2016). The measured δ202Hg values of the E2-3s mudstones from the Liaohe oilfield are between −1.96‰ and −2.48‰ (Table S8, Fig. 5). The oil-type gases from mudstones and shales sampled for this study have similar Hg δ202Hg values to the inferred source rocks (Fig. 5). Additionally, organic-rich marine sediments are considered to be the source of most oil and gas worldwide. For example, mid-Pleistocene sapropels from the Mediterranean Sea have 202Hg values from −1.11‰ to −0.57‰ (Gehrke et al., 2009), and black shales from south China and Australia have δ202Hg values from −3.02‰ to −1.71‰ (Yin et al., 2017) and −1.66‰ to −0.20‰, respectively (Blum and Anbar, 2010). We speculate that the formation of oil-type gas is associated with limited MDF, in contrast to the formation of coalbed gas. The formation of oil-type gas involves primary cracking of kerogens and secondary cracking of oils. The details of these processes depend on the nature of the parent materials (Tissot and Welte, 1984). The organic matter in coal is different from the organic matter in oil; coals contain mainly humic organic matter, whereas oils contain mainly sapropelic organic matter. Decomposition of the organic matter follows different reaction pathways in coalfields and oil fields, so the extent of MDF involved in the formation of coalbed gas and oil-type gas is expected to differ. Further work is required to test this hypothesis and to investigate the Hg isotopic signature of crude oils and other potential sources of natural gas. Recently, negative δ202Hg values between −3.75‰ and −0.68‰ (n = 7) and mostly positive Δ199Hg values (−0.02‰–0.63‰ (n = 7) were reported for natural gas from different sites worldwide (Washburn et al., 2018). Detailed information was not provided on the potential source rocks of the natural gases, but the results of our work indicate that the natural gases studied were oil-type gas rather than coalbed gas.
5. Conclusions We analyzed typical natural gases from China, and found high Hg levels that pose serious environmental concerns, given the increasing importance of natural gas as an energy source worldwide. We show, for the first time, that the Hg0 isotopic signatures of coalbed gas and oiltype gas are different, and that the Hg0 isotopic signature can be used to identify the origin of natural gases. The effects of other sources on the Hg isotopic signature cannot be excluded, but the coalbed gas was generally characterized by a negative MIF signature, suggesting that the Hg in coalbed gas is mainly derived from the source coals. The oil-type gases showed a positive MIF signature similar to that of their source rocks, indicating that the Hg in these gases was mainly sourced from the E2-3s mudstones. It is likely that significant MDF occurred during the formation of the coalbed gas, whereas MDF was limited during the formation of the oil-type gas. In future, it is likely that the Hg0 isotopic composition of natural gases worldwide, including biogas and shale gas, will be measured, and that the Hg0 isotope signature will be applied widely to aid the gas exploration industry by identifying the origin of natural gases. Acknowledgments This research was supported by the National Natural Science Foundation of China (41573006; 41372360). We thank Wei Yan of State Key Laboratory of Environmental Geochemistry, Chinese Academy of Sciences, for assistance in measuring Hg isotopes. We thank the editor and two anonymous reviewers for their thoughtful comments, which significantly improve the quality of this paper. Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.apgeochem.2019.104415. 7
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The mercury isotope signatures of coalbed gas and oil-type gas: Implications for the origins of the gases
T
Shunlin Tanga,∗, Yuping Zhoua, Xiaojie Yaoa, Xinbin Fengb,∗∗, Zhaopeng Lia, Gaoen Wua, Zhu Guangyouc a
Institute of Resources and Environment, Henan Polytechnic University, Jiaozuo, Henan province, 454000, China State Key Laboratory of Environmental Geochemistry, Institute of Geochemistry, Chinese Academy of Sciences, Guiyang, 550081, China c Department of Petroleum Geology, Research Institute of Petroleum Exploration and Development, PetroChina, Beijing, China b
ARTICLE INFO
ABSTRACT
Editorial handling by Dr C S Eckley
The concentration of mercury vapor (elemental mercury, Hg0) in natural gases has been used to differentiate between coalbed gas and oil-type gas. However, the concentrations of Hg0 in coalbed gas and oil-type gas are highly variable, and its use as a genetic indicator is problematic. Here, for the first time, we report significant differences in the mass-dependent fractionation (MDF, measured with δ202Hg) and the mass-independent fractionation (MIF, measured with Δ199Hg, Δ200Hg and Δ201Hg) of Hg0 isotopes between coalbed gas and oil-type gas. Coalbed gas has an extremely negative δ202Hg (−5.8‰ to −3.08‰) and negative Δ199Hg (−0.19‰ to −0.01‰) relative to the assumed source, which is Permian coal from the Henan Province, China. Oil-type gas is characterized by less negative δ202Hg (−3.08‰ to −0.77‰) and positive Δ199Hg (0.06‰–0.30‰) relative to its E2-3s source rocks in the Liaohe oilfield (dark mudstones: δ202Hg = −1.96‰ to −2.48‰, Δ199Hg = 0.09‰–0.17‰). This significant difference in the MIF can be used to distinguish between coalbed gas and oil-type gas. Notably, the Δ200Hg values of our samples are as high as 0.15‰. We suggest that significant Hg0 MDF might occur during the formation of coalbed gas, but not during the formation of oil-type gas. This study highlights the potential of Hg0 isotopes as proxies for the source of natural gases.
Keywords: Mercury Mercury isotopes Gas genesis Coalbed gas Oil-type gas
1. Introduction Knowledge of the origins of natural gases is practically and theoretically useful in the oil and gas exploration industries. For example, the efficiency of Chinese natural gas exploration was low prior to 1980, because exploration was guided only by traditional theories relevant to oil-type gases. The discovery of coalbed gas after 1980 has expanded the scope of natural gas exploration in China (Dai et al., 2010). A range of geochemical proxies have been used to characterize the generation and origins of the natural gases; these include stable carbon and nitrogen isotopes, noble gas isotopes, clumped isotopes, chemical compositions, microbial information, hydrochemistry, and thermal maturity (Schoell, 1980; Stolper et al., 2014a). In addition, it has been shown that the concentration of mercury vapor (elemental mercury, Hg0) in natural gases provides useful genetic information (Dai et al., 2010). Mercury (Hg) has a high affinity for organic matter and sulfides (Haitzer et al., 2002); it is released into hydrocarbon reservoirs by
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thermal reduction or decomposition of Hg compounds during burial and tectonism (Rojey, 1997; Peters et al., 2005). At ambient temperatures, Hg is soluble in liquid aliphatic hydrocarbons at concentrations of 1–3 μg/mL, which is much higher than its solubility in water (0.05 μg/ mL) (Wilhelm and Bloom, 2000). The dominant Hg species in natural gases is Hg0, which accounts for > 85% of the total Hg (Ezzeldin et al., 2016). Mercury in natural gas occurs at concentrations of 10–400 000 ng/m3, depending on the geological setting in which the natural gas is found (Bingham, 1990; Dai, 1992). The Hg0 concentrations in natural gases are typically several orders of magnitude higher than those in ambient air (Dai, 1992; Zettlitzer et al., 1997; Lang et al., 2012). Mercury in natural gas can damage the aluminum heat exchanger boxes used to separate ethane and heavy hydrocarbons from commercial gas, poison catalysts, and increase the health risks to field workers in natural gas treatment plants (EGAS, 2011; Ezzeldin et al., 2016). It has been proposed that the concentration of Hg0 reflects the origin of natural gas (Ozerova, 1983); Dai (1992) showed that Hg0 concentrations are typically greater than 700 ng/m3 in coalbed gases,
Corresponding author. Corresponding author. E-mail addresses: [email protected] (S. Tang), [email protected] (X. Feng).
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https://doi.org/10.1016/j.apgeochem.2019.104415 Received 13 June 2019; Received in revised form 15 August 2019; Accepted 30 August 2019 Available online 30 August 2019 0883-2927/ © 2019 Elsevier Ltd. All rights reserved.
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and less than 500 ng/m3 in oil-type gases. However, subsequent studies have shown a substantial overlap between the Hg0 concentrations of oil-type gas (4–142 000 ng/m3) and coalbed gas (200–3 000 000 ng/ m3) (Liu, 2013). In addition, Hg0 concentrations vary significantly within a single gas field. Therefore, the Hg0 concentration alone is an ambiguous proxy of the source of a natural gas. Mercury has seven natural stable isotopes (196Hg, 198Hg, 199Hg, 200 Hg, 201Hg, 202Hg and 204Hg), and their ratios might provide additional information on the genesis of natural gases. Mass-dependent fractionation (MDF, denoted by δ202Hg) and mass-independent fractionation (MIF, denoted by Δ199Hg, Δ200Hg and Δ201Hg) of Hg isotopes are observed in nature, with variations greater than 10‰ for δ202Hg, Δ199Hg, and Δ201Hg, and around 1‰ for Δ200Hg (Blum et al., 2014; Sun et al., 2019). Some degree of MDF is associated with most abiotic and biotic Hg transformations, while MIF is mainly associated with photochemical processes (Bergquist and Blum, 2007; Zheng and Hintelmann, 2009). The Hg isotopic ratios show promise as a method to distinguish between different sources of natural gases. Washburn et al. (2018) presented the first compilation of the Hg isotopic compositions of natural gas. These workers analyzed the Hg-removal catalyst units that contained Hg after natural gas production. The values of δ202Hg and Δ199Hg varied from −3.75‰ to −0.68‰ and −0.02‰ to 0.65‰, respectively. The results indicate that the Hg isotopic composition can be used as a proxy for natural gas Hg emissions in some gas fields. In natural gases, MDF of the Hg isotopes occurs during biogenic and thermogenic formation processes (Rojey, 1997). In contrast, while a small MIF signature (< 0.2‰) can be induced in natural gases by changes to Hg speciation in the absence of light (e.g., reduction or oxidation in the dark) (Zheng and Hintelmann, 2010), a significant MIF signature (> 0.2‰) requires photochemical reactions, which are unlikely to occur underground. Therefore, we hypothesize that natural gases with different origins might preserve the Hg isotope signature, and in particular the MIF signature, of their source materials. To test this hypothesis, we measured the Hg0 isotopic composition of coalbed gas and oil-type gas from three gas fields in China. The objectives are to: (1) understand Hg isotope fractionation during the formation of natural gases; (2) verify whether different natural gases have distinguishable Hg0 isotope compositions; and (3) establish a new proxy for the origin of natural gas that can be used in natural gas exploration.
gas-bearing coal seam located at 470–947 m depth. The gas-bearing coal seam has an average thickness of 7.8 m, and is part of the Permian Shanxi Formation (P1), which formed in a tidal flat to fluvial deltaic setting (Liu, 2010; Fu, 2005). The coalbed gas consists of > 99.5% methane, and is used as a commercial fuel without post-extraction processing. 2.2. Sampling and analysis of mercury concentrations The natural gas samples were taken from pipelines connected to wellheads at the field sites. The Hg0 was separated from the untreated natural gas samples using a sampler consisting of three-stage serial impingers (500 mL each, Environmental Supply Company, USA) (Fig. 2). The first impinger was empty, and was used to remove water vapor from the gas and maximize Hg0 trapping efficiency within the succeeding impingers. The second to fourth impingers were filled with 100 mL of a trapping solution containing 4% (w/v) KMnO4 and 10% H2SO4 (v/v), that trapped the Hg0 present in the natural gas. The combination of KMnO4 and H2SO4 in solution has been used to trap Hg0 in gases produced by volatilization of coal and soil samples using a step heating combustion procedure (Biswas et al., 2008; Lefticariu et al., 2011), and from flue gases (Tang et al., 2016, 2017). A fifth impinger was packed with ~100 mg allochroic silicagel to absorb any water vapor in the remaining gas, so that the gas volume could be measured accurately in a dry gas flow meter. The five impingers were connected by U-type borosilicate glass tubes fastened together with flexible iron clamps. Reagent blanks of the KMnO4 and H2SO4 solution and the main chemicals used in recovery and analysis were measured; all results were below 6 ng/L (Table S1). To prevent Hg0 sorption onto the walls of the sampling and connecting tubes and borosilicate impingers, the sampling device was flushed repeatedly with the untreated natural gas from the wellheads in the field before sampling. Then, the raw natural gas was released to the five impingers via a 5 m Teflon tube connected to the pressure gauge at the wellhead. The flow rate of the natural gas was adjusted to ~6 L/min, and the collection time was greater than 3 h. At least 1 m3 of natural gas of each sample was collected (except for three samples of 0.83–0.97 m3) to ensure sufficient Hg for the isotopic analysis. During the sampling, the trapping solution retained a brown color, indicating that an excess of KMnO4 was maintained. Immediately after sampling, the three trapping solutions were reduced using appropriate amounts of 0.5 mL NH2OH–HCl (30%, w/v) and transferred into a 250 mL pre-cleaned borosilicate glass bottle. To test the efficiency of Hg0 trapping, we used our sampling device in the laboratory to trap the Hg0 produced by 5 mL of a Hg standard solution (NIST SRM 3133) diluted to give Hg concentrations of 10 ng/ mL, 50 ng/mL, 100 ng/mL, 200 ng/mL and 400 ng/mL. The Hg standard solutions were diluted to 50 mL with 18.2 MΩ cm−1 water and pumped with a peristaltic pump (Longer Pump LEAD-2, Halma in China) at a flow rate of 0.25 mL/min through 50 mL SnCl2 (3%) solutions. Petroleum gas, from which the Hg had been removed using a 100 mL aqua regia prior to use, was used to purge the product Hg0 at a flow rate of ~6 L/min for at least 3 h. The trapping solutions from all three impingers were analyzed for Hg and the Hg isotopic ratios were measured in solutions with Hg concentrations greater than 1.0 ng/mL (Table 2S); this limit was chosen to match the sensitivity of the multicollector inductively coupled plasma mass spectrometry (MC-ICP-MS, Neptune Plus) technique. The test results show that 95.2%–99.5%, 0.8%–5.5% and 0.2%–0.9% of the Hg in the standard solutions were trapped by the first, second and third impingers, respectively (Table S2). The trapping solutions were analyzed using cold vapor atomic fluorescence spectroscopy (Brooks Rand Model III) at the Institute of Resources and Environment, Henan Polytechnic University. The Hg concentration in the natural gas was calculated from the sum of the masses of Hg in the three trapping solutions, divided by the total
2. Methods 2.1. Geological background Untreated natural gas samples were collected at the wellheads of gas wells within three gas fields (Fig. 1): (1) the Liaohe oilfield in the Liaohe Basin, northeastern China, which is one of China's most important oil and gas production areas; (2) the Zhongyuan oilfield in the Bohai Bay Basin, central China; and (3) the No.6 coal mine, Hebi coalfield, Henan Province, China. Natural gases from the Liaohe and Zhongyuan oilfields are thought to be of terrestrial origin, with source rocks deposited dominantly in lacustrine and fluvial deltas. Stratigraphically, the source rocks belong to the Eocene Shahejie Formation (E2-3s); they are organic-rich mudstones and shales that contain algae and ostracod fossils (Wang et al., 2012; Wu et al., 2013). Five hydrocarbon source rock samples (dark mudstones) were collected from outcrops of the Eocene Shahejie Formation (E2-3s) in the Liaohe Oilfield. The total mercury concentration and mercury isotopes were analyzed to characterize the source rock, because there are few data that describe the Hg isotope composition of pre-anthropogenic terrestrial sediments. The natural gases of the Liaohe and Zhongyuan oilfields were extracted from gas reservoirs at depths of 2600–3200 m (Zhu et al., 2013, 2014), and > 3000 m from the surface wellheads, respectively. Untreated coalbed gas from the Hebi coal mine was extracted from a 2
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Fig. 1. Structural maps and locations of sampling sites ( ). (a) Structural map of the Liaohe oilfield in the western sag of the Liaohe Basin, northeastern China (Huang et al., 2008). (b) Structural map of the Zhongyuan oilfield in the Bohai Bay Basin, central China (Internal data, no published). (c) Structural map of the Hebi coalfields of Henan province, China (Fu, G.Q., 2005, in Chinese).
Fig. 2. Schematic illustration of the sampling device. 1: Sampling outlet, 2: First impinger (empty); 3–5: Three impingers filled with KMnO4 (4%) + H2SO4 (10%) solutions; 6. Impinger filled with silica gel; 7. Dry gas flow meter.
volume of the sampled gas. The first, second, and third impingers trapped 76%–97%, 2.9%–21.5%, and 0.1%–8.3% of the Hg, respectively. The five samples of dark hydrocarbon source mudstone were milled
and sieved to 200 mesh. Appropriate amounts of the powdered solid samples were weighed into 45 mL centrifuge tubes, and digested using 10 mL of reverse aqua regia (HNO3: HCl = 3:1, v/v), selected to accommodate the high organic content of the samples. The centrifuge 3
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tubes containing the digested samples were shaken overnight and placed in a water bath. The water bath was kept at 50 °C for half an hour, then heated to 95 °C and held at that temperature for 2 h. After cooling to room temperature, the digested samples were filtered into new 45 mL centrifuge tubes using disposable syringes and syringedriven 0.45 μm PVDF filters (Millex, OD = 33 mm). The filtered digested samples were capped, labeled, and stored in a refrigerator prior to analysis for total Hg using Brooks Rand Model III.
proxy for the origin of natural gases. The Hg isotopic compositions of samples from all three trapping impingers were measured for four samples with high Hg concentrations (L-2016-4-15-3, L-2016-4-17-3, L-2016-4-17- and L-2016-5-21-3) (Table S6). The δ202Hg value measured in the sample from the first impinger was generally the lowest, and the greatest difference in the δ202Hg values among the three impingers for a single sample was 2.52‰. One reason for the difference among the impingers is that there is likely to be a small amount (< 15%) of Hg species other than Hg0 in natural gas, including particulate Hg and organic mercury (Ezzeldin et al., 2016). These species might not be reduced to Hg0 and trapped in the first solution, but might be reduced to Hg0 and trapped in the second or third solutions, with a consequent increase in Hg concentrations and changes to the isotopic composition. Alternatively, MDF might have occurred during Hg trapping, such that the lighter Hg isotopes were trapped preferentially within the first impinger. The Δ199Hg values of samples from the three impingers are identical, within analytical uncertainty, suggesting that MIF did not occur during the Hg trapping process. The lowest percentage of Hg trapped by the first impinger is 76%. Using this value, and the largest measured difference in δ202Hg values of 2.52‰ between the first and third impingers, the difference in δ202Hg between the total Hg and the Hg in the first impinger is < 0.60‰; this value is considered to be a maximum value for the systematic uncertainty related to differences between the impingers. Furthermore, > 95% of the Hg0 was trapped by the first impinger in most cases, and the Hg isotopic composition of solutions from the first impinger in the laboratory validation test were within the 2SD uncertainty of the accepted value for NIST SRM 3133 (Table S2). Therefore, the Hg isotopic composition of the solution from the first impinger was considered to represent the Hg0 isotopic composition of the natural gas (Table S7). The Hg isotopic compositions of the coalbed and oil-type gases are shown in Fig. 3 and Table S7. The Hg0 isotope compositions of the coalbed gas samples are significantly different from those of the oil-type gas. The coalbed gases from the Hebi coalfield have very negative δ202Hg (−5.89‰ to −3.08‰) and slightly negative Δ199Hg values (−0.19‰ to −0.01‰), with average values of −4.77‰ ± 0.87‰ (n = 7, 1SD) and −0.11‰ ± 0.06‰ (n = 7, 1SD), respectively. The oil-type dry gases of the Liaohe and Zhongyuan oilfields showed higher δ202Hg values (−3.03‰ to −0.77‰, average = −1.89‰ ± 0.66‰, n = 13, 1SD) than the coalbed gas samples, and positive Δ199Hg values (0.15‰–0.30‰, average = 0.20‰ ± 0.06‰, n = 13, 1SD). The oiltype wet gases of the Liaohe and Zhongyuan oilfields had similar δ202Hg (−3.08‰ to −1.39‰, average = −2.08‰ ± 0.63‰, n = 10, 1SD) and Δ199Hg (0.06‰–0.21‰, average = 0.13‰ ± 0.05‰, n = 10, 1SD) to oil-type dry gases from the two oilfields and a Hg isotope signature similar to that of the source rocks (Table S8: δ202Hg = −1.96‰ to −2.48‰, average = −2.26‰ ± 0.20‰; Δ199Hg = 0.09‰–0.17‰, average = 0.13‰ ± 0.03‰, n = 5, 1SD). Therefore, we can distinguish between coalbed gas and oil-type gas based on the significant difference of Hg0 MIF signature. Given the similarities, results from the dry and wet oil-type gas were combined and are referred to subsequently as oil-type gas. The difference of 2.8‰ between the average δ202Hg values of coalbed gas and oil-type gas is more than four times larger than the largest difference in δ202Hg values (0.60‰) that might have arisen from analytical artefacts, as discussed above. The linear correlation between Δ199Hg and Δ201Hg gives a value for Δ199Hg/Δ201Hg of 0.76 ± 0.02 (R2 = 0.78, Pearson's correlation coefficient = 0.88) for the coalbed gas samples and 1.17 ± 0.03 (R2 = 0.79, Pearson's correlation coefficient = 0.89) for the oil-type gas samples (Fig. 4). This indicates that additional sources of Hg, such as Hg in hydrothermal fluids, were present in the natural gases.
2.3. Mercury isotope analysis The Hg isotopes were analyzed in the trapping solutions from the first impinger, trapping solutions from the second and third impingers with Hg concentrations > 1.0 ng/mL, and the digests of the five mudstone samples. The trapping solutions were diluted to 1.0–2.0 ng/mL Hg using 18.2 MΩ cm−1 water. The Hg isotopic ratios were measured using a multi-collector inductively coupled plasma mass spectrometer (MC-ICP-MS, Neptune Plus) at the State Key Laboratory of Ore Deposit Geochemistry, Chinese Academy of Sciences, China, following the method described by Tang et al. (2017). The sensitivity of the response to 202Hg was 0.8–0.9 V per ng/mL of Hg. The signal for 202Hg in the blank solutions was always < 10 mV. The instrumental mass bias was corrected using a sample–standard bracketing method. The Hg concentrations and matrices of the bracketing standard (NIST SRM 3133) were matched to the sample solutions. Uncertainties, based on measurements of NIST SRM 3133, are provided in Table S3. The Hg isotope ratios are reported using the delta (δ) notation, to represent the per mil deviation of the samples from the bracketing standard (Blum and Bergquist, 2007): δXXXHg (‰) = [(XXXHg/198Hgsample)/(XXXHg/198HgNIST3133) 1] × 1000,
(1)
where xxx is the mass of the selected Hg isotopes (199–202). The MIF signature is reported using the capital delta notation (ΔxxxHg), which represents the deviation of the measured δxxxHg from the δxxxHg calculated for MDF using the relationship: ΔXXXHg (‰) = δXXXHg - βXXX × δ202Hg, 199
200
(2) 201
where β is 0.252 for Hg, 0.5024 for Hg and 0.752 for Hg, respectively (Blum and Bergquist, 2007). The analytical uncertainty was determined using repeated analyses of the UM-Almadén secondary Hg standard solution, which has a similar Hg concentration (1–2 ng/g Hg) to the unknowns, and an acid matrix. Average values of the 1 ng/g and 2 ng/g UM-Almadén standard solutions were −0.53‰ ± 0.10‰ (2SD, n = 13) and −0.51‰ ± 0.10‰ (2SD, n = 11) for δ202Hg, −0.03‰ ± 0.04‰ (2SD, n = 13) and −0.04‰ ± 0.04‰ (2SD, n = 11) for Δ199Hg, and −0.00‰ ± 0.04‰ (2SD, n = 13) and −0.00‰ ± 0.06‰ (2SD, n = 11) for Δ201Hg (Table S4). These values are consistent with previously reported values (Blum and Bergquist, 2007; Tang et al., 2017). The uncertainties reported for the Hg isotope ratios in this study correspond to the largest value of the external 2SD uncertainty derived from repeated measurements of the UM-Almadén standard and the 2SD uncertainty derived from two replicate analyses of the sample solutions. 3. Results The Hg0 concentrations in coalbed gas from the Hebi coalfield are 56–155 ng/m3 (average: 123 ± 3 5 ng/m3, n = 7, 1SD) (Table S5). These values are lower than those recorded for oil-type wet gas (31–467 ng/m3, average = 216 ± 127 ng/m3, n = 1 5, 1SD) from the Liaohe oilfield, and oil-type dry gas (31 626–108 408 ng/m3, average = 54 676 ± 23 980 ng/m3, n = 16, 1SD) from the Zhongyuan oilfield. These results are inconsistent with the conclusions of Dai et al. (2001), and indicate that Hg0 concentrations might not be a suitable 4
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Fig. 3. Plot of δ202Hg vs. Δ199Hg for coalbed gas, oil-type wet gas and dry gas. The ellipses show the mean (inner ellipse) and 95% confidence levels (outer ellipse) of the δ202Hg and Δ199Hg. Calculations performed using the OriginPro 2017C software.
4. Discussion
material, which might include coal, oil, and shales (Tissot and Welte, 1984), and is also affected by the thermal evolution of the parent materials. The formation of natural gas is thermally driven and Hg0 is highly volatile, so it is commonly believed that Hg0 in natural gas is affected by tectonic activity (Bingham, 1990; Dai, 1992). Tectonic activity provides heat to drive thermal processes and might also provide
4.1. Differences in the mercury concentrations of coalbed gas and oil-type gas The Hg0 in natural gas is sourced mainly from the gas source
Fig. 4. Plot of Δ201Hg vs. Δ199Hg for coalbed gas and oil-type wet and dry gas. The error bars show uncertainties at the 2SD level. The Δ199Hg/ Δ201Hg ratio (1SD) is different to one, which indicates that additional sources of Hg (e. g., hydrothermal fluids) contributed to the natural gases. Calculations performed using the OriginPro 2017C software.
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additional Hg carried by hydrothermal fluids, in regions where hydrothermal activity is frequent. The Hg0 concentrations of coalbed gas (56–155 ng/m3), oil-type wet gas (31–467 ng/m3) and oil-type dry gas (31 626–108 408 ng/m3) measured in the present study (Table S5) are generally consistent with the results of previous studies that reported levels of Hg0 in natural gas between 10 and 400 000 ng/m3 (Bingham, 1990; Han et al., 2013). Natural gas has become an important and rapidly growing source of energy globally, so these high Hg0 concentrations are worthy of attention. A previous study by Dai et al. (2001) documented the concentration of Hg0 in 102 coalbed gas samples from 32 coal fields and 242 oil-type gas samples from 29 oil-gas fields in China, and concluded that the typical Hg0 concentrations of coalbed gas and oil-type gas are > 700 ng/m3 and < 500 ng/m3, respectively. Based on these findings, they proposed that the concentration of Hg0 is a useful indicator of the origin of a natural gas. Our results are inconsistent with the conclusions of Dai et al., but consistent with the results of another recent study that did not find a difference in the concentrations of Hg0 between coalbed gas and oil-type gas in the Tarim basin, China (Liu, 2013). Natural variations in the gas to oil ratio can cause large variations in Hg0 concentrations (Ryzhov et al., 2003; Faramawy et al., 2009), and a continuous decrease in the Hg0 concentrations in natural gases was attributed to precipitation of Hg0 inside a pipeline between the wellhead and treatment facilities (Wilhelm and Bloom, 2000). Thus, the use of Hg0 concentration as an indicator of the origin of a natural gas is problematic.
coalbed gas formed by microbial decomposition of organic matter within the coal (Smith and Williams, 1984). Any Hg (II) bound to organic matter might be reduced to Hg0 during this process (Haitzer et al., 2002). Thermogenic coalbed gas generally forms from 150 °C to 220 °C, associated with the slow decomposition of organic material within the coal (Stolper et al., 2014b). As the organic materials decompose (e.g., through cracking of the kerogens), Hg0 and methane desorb from the organic material to form gases that diffuse slowly through the pores within the coal seams. The Hg0 and methane accumulate in the coal pores and are released when pressure decreases in response to uplift or erosion of the coal basin. To summarize, generation of biogenic and thermogenic coalbed gas is likely to involve biotic and abiotic processes (e.g., volatilization, diffusion, thermal reduction). Incomplete transformation of Hg during these processes would cause significant enrichment in the lighter Hg isotope in the product Hg0 within the coalbed gas (Kritee et al., 2007, 2008; Sun et al., 2013a, b; Koster Van Groos et al., 2014). In addition, if ~50% of the Hg in coalbed gas is from hydrothermal sources, as discussed above, then evaporation of Hg0 from the hydrothermal fluids might contribute to the lower δ202Hg in coalbed gas (Smith et al., 2005; Sherman et al., 2009). 4.3. Mercury isotope fractionation during the genesis of oil-type gas The wet and dry oil-type gases are enriched in the heavier and odd Hg isotopes relative to the coalbed gas, and can be distinguished from the coalbed gas, based on the significant difference in Δ199Hg (p < 0.01) and δ202Hg (Fig. 3). According to geological surveys, the sediment sources of the oil-type gases of this study are terrestrial dark mudstones and shales of the Eocene Shahejie Formation (E2-3s). The Hg isotope compositions of the dark mudstone samples (E2-3s) from the Liaohe oilfield are similar to those of the oil-type gases from the two oilfields (Table S8: δ202Hg = −1.96‰ to −2.48‰, average = −2.26‰ ± 0.20‰; Δ199Hg = 0.09‰–0.17‰, average = 0.13‰ ± 0.03‰, n = 5, 1SD). This indicates that the MIF signature observed in the oil-type gases is largely inherited from the source materials. In addition, our oil-type gas samples and the source mudstone samples all have positive Δ199Hg values, and these values are similar to those of lake sediments from pristine areas (Δ199Hg: +0.12 to +0.31‰, Yin et al., 2016). Notably, our samples also show slightly non-zero Δ200Hg values (up to 0.15‰); non-zero Δ200Hg values have previously been observed only in rain (Gratz et al., 2010; Chen et al., 2010; Demers et al., 2013; Enrico et al., 2016), freshwater fish (Bergquist and Blum, 2007), coastal sea water (Štrok et al., 2015), and black shales (Yin et al., 2017). The oil-type gases were generated from marine and terrestrial (lacustrine or fluvial) sediments enriched in organic matter. Sapropels and black shales in the oceans are typical marine source materials that generate oil gas (Tissot and Welte, 1984). Sapropels and black shales commonly show positive Δ199Hg values (Gehrke et al., 2009; Grasby et al., 2017; Yin et al., 2017; Wang et al., 2012). Therefore, Δ199Hg cannot be used alone as a proxy for the source sediment type. The Δ199Hg/Δ201Hg ratio of the analyzed oil-type gases is 1.17 ± 0.13, which is slightly different from the ratio generated by Hg (II) photoreduction (Fig. 4). This indicates that Hg from sources with a lower Δ199Hg was probably incorporated into the oil-type gas. The Liaohe and Zhongyuan oilfields are both cut by well-developed faults (Peng et al., 2019), so some of the Hg0 might be derived from deep fluids with near-zero Δ199Hg. We speculate that Δ199Hg values of the oil-type gas, if it had not been mixed with deeply sourced fluids, might have been more positive than our measured values. Furthermore, based on evidence from the literature and the new data presented here, we suggest that only marine or continental organic-rich sediments with positive Δ199Hg values are effective source rocks for oil or gas. However, further research is required to test this hypothesis. Previous workers have reported large variations in the δ202Hg
4.2. Mercury isotope fractionation during formation of coalbed gas Values of δ202Hg were plotted against Δ199Hg for the coalbed and oil-type gases (Fig. 3). Negative Δ199Hg values have been reported for coals worldwide (−0.11‰ ± 0.18‰ and coals from the Henan Province (−0.24‰ ± 0.09‰, n = 6, 1SD), the source of the coalbed gas in this study (Yin et al., 2014; Sun et al., 2014a). The Δ199Hg values of the coalbed gas analyzed in this study are negative (−0.11‰ ± 0.06‰, n = 7, 1SD), but less negative than those of the Henan coals. In addition, the Δ199Hg/Δ201Hg ratio of the coalbed gas is 0.76 ± 0.18 (Fig. 4), which is different to that measured for world coals (1.07 ± 0.04) and Henan coals (1.10 ± 0.06) (Yin et al., 2014; Zheng and Sun, 2016). The difference in slope indicates that the MIF signature of coalbed gas is not inherently unchanged from the source coal, but might reflect the presence of Hg with higher Δ199Hg in the coalbed gas. Previous studies have shown that geogenic processes do not impart a MIF signature (Δ199Hg ~ 0), based on the analysis of hydrothermal minerals in coals (Lefticariu et al., 2011; Sun et al., 2014b). Furthermore, positive MIF signatures in samples from the coalfields of the Shandong and Anhui provinces, China, and from Inner Mongolia, were interpreted as a record of hydrothermal Hg (Sun et al., 2014b; Zheng and Sun, 2016; Zheng et al., 2018; Peng et al., 2019). Therefore, we speculate that the coalbed gas contains a mixture of geogenic Hg from hydrothermal fluids with a near-zero or positive Δ199Hg and Hg derived from the coals. An isotope mixing model was used to show that the source coals and hydrothermal fluids contributed equal amounts of Hg to the coalbed gas, assuming that the source coals and hydrothermal fluids had Δ199Hg values of −0.24‰ and 0.00‰, respectively (Sun et al., 2014a). Therefore, we speculate that the Δ199Hg value of the Hebi coalbed gas is more negative than the measured values presented in this study. The Hebi coalbed gas had a much lower δ202Hg (−4.77‰ ± 0.87‰, n = 7, 1SD) than the world coal compilation (−1.16‰ ± 0.79‰) and coals from the Henan Province (−1.3‰ ± 0.7‰, n = 6) (Yin et al., 2014; Zheng and Sun, 2016) (Fig. 5), suggesting that there was significant MDF of Hg isotopes during the formation of coalbed gas. Further research is necessary to elucidate the details of the MDF, but it is possible to propose a hypothesis involving desorption and diffusion that explains some of the observations. During peatification and early coalification, biogenic 6
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Fig. 5. Plot of δ202Hg vs. Δ199Hg, showing results from coalbed gas and oil-type gas (this study), Permian coal from Henan province, China (Yin et al., 2014; Sun et al., 2014a), lake sediments from the Qinghai and Nam Co lakes of the Tibetan Plateau (Yin et al., 2016), and mudstones of the Eocene Shahejie Formation from the Liaohe oilfield (this study). The 95% confidence ellipse centered on the mean value was calculated using the OriginPro 2017C software.
values of pre-anthropogenic sediments and organic-rich lacustrine sediments far from sources of pollution (Yin et al., 2016, Fig. 5). For example, sediment profiles from the Qinghai and Nam Co lakes on the Tibetan Plateau have δ202Hg values from −5.04‰ to −2.16‰ (Yin et al., 2016). The measured δ202Hg values of the E2-3s mudstones from the Liaohe oilfield are between −1.96‰ and −2.48‰ (Table S8, Fig. 5). The oil-type gases from mudstones and shales sampled for this study have similar Hg δ202Hg values to the inferred source rocks (Fig. 5). Additionally, organic-rich marine sediments are considered to be the source of most oil and gas worldwide. For example, mid-Pleistocene sapropels from the Mediterranean Sea have 202Hg values from −1.11‰ to −0.57‰ (Gehrke et al., 2009), and black shales from south China and Australia have δ202Hg values from −3.02‰ to −1.71‰ (Yin et al., 2017) and −1.66‰ to −0.20‰, respectively (Blum and Anbar, 2010). We speculate that the formation of oil-type gas is associated with limited MDF, in contrast to the formation of coalbed gas. The formation of oil-type gas involves primary cracking of kerogens and secondary cracking of oils. The details of these processes depend on the nature of the parent materials (Tissot and Welte, 1984). The organic matter in coal is different from the organic matter in oil; coals contain mainly humic organic matter, whereas oils contain mainly sapropelic organic matter. Decomposition of the organic matter follows different reaction pathways in coalfields and oil fields, so the extent of MDF involved in the formation of coalbed gas and oil-type gas is expected to differ. Further work is required to test this hypothesis and to investigate the Hg isotopic signature of crude oils and other potential sources of natural gas. Recently, negative δ202Hg values between −3.75‰ and −0.68‰ (n = 7) and mostly positive Δ199Hg values (−0.02‰–0.63‰ (n = 7) were reported for natural gas from different sites worldwide (Washburn et al., 2018). Detailed information was not provided on the potential source rocks of the natural gases, but the results of our work indicate that the natural gases studied were oil-type gas rather than coalbed gas.
5. Conclusions We analyzed typical natural gases from China, and found high Hg levels that pose serious environmental concerns, given the increasing importance of natural gas as an energy source worldwide. We show, for the first time, that the Hg0 isotopic signatures of coalbed gas and oiltype gas are different, and that the Hg0 isotopic signature can be used to identify the origin of natural gases. The effects of other sources on the Hg isotopic signature cannot be excluded, but the coalbed gas was generally characterized by a negative MIF signature, suggesting that the Hg in coalbed gas is mainly derived from the source coals. The oil-type gases showed a positive MIF signature similar to that of their source rocks, indicating that the Hg in these gases was mainly sourced from the E2-3s mudstones. It is likely that significant MDF occurred during the formation of the coalbed gas, whereas MDF was limited during the formation of the oil-type gas. In future, it is likely that the Hg0 isotopic composition of natural gases worldwide, including biogas and shale gas, will be measured, and that the Hg0 isotope signature will be applied widely to aid the gas exploration industry by identifying the origin of natural gases. Acknowledgments This research was supported by the National Natural Science Foundation of China (41573006; 41372360). We thank Wei Yan of State Key Laboratory of Environmental Geochemistry, Chinese Academy of Sciences, for assistance in measuring Hg isotopes. We thank the editor and two anonymous reviewers for their thoughtful comments, which significantly improve the quality of this paper. Appendix A. Supplementary data Supplementary data to this article can be found online at https:// doi.org/10.1016/j.apgeochem.2019.104415. 7
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