Mercury Isotopes in Shale Gas From Wufeng-Longmaxi Shale Formation of Sichuan Basin, Southern China: A Preliminary Investigation

A series of investigations have been conducted concerning the study of traditional stable isotopes and rare gas stable isotopes in natural gas. However, little is known regarding non-traditional stable isotopes of mercury in natural gas, especially in the development and utilization of shale gas in recent years. In fact, the presence of mercury in natural gas (including shale gas) provides a basis for research on mercury isotopes. Mercury was extracted from shale gas at the Wufeng-Longmaxi Formation in the YS108 block of the Zhaotong National shale gas demonstration area in the Sichuan Basin by using an acid potassium permanganate solution, followed by the analysis of mercury content and stable isotope composition. The mercury content in the marine shale gas at the Wufeng-Longmaxi Formation ranged from 171 to 2,906 ng/m³, with an average of 1,551.08 ± 787.08 ng/m³ (n = 37, 1 SD). The Δ¹⁹⁹Hg values of mercury stable isotopes range from 02‰ to 0.39‰, with an average of 22‰ ± 0.08‰ (n = 37, 1 SD); the δ²⁰²Hg values range from −1.68‰ to −0.04‰, with an average of −0.87‰ ± 0.31‰ (n = 37, 1 SD), which are significantly different from the Δ¹⁹⁹Hg and δ²⁰²Hg information of coalbed gas, but similar to the Δ¹⁹⁹Hg and δ²⁰²Hg information of terrestrial oil-type gas and the Δ¹⁹⁹Hg in the main hydrocarbon-forming organic matter of lower organisms such as algae (t-test, p > 0.05). This indicates that terrestrial target strata with abundant algae or strata with positive Δ¹⁹⁹Hg are the target strata for the exploration of terrestrial oil and gas.

Introduction

As proposed by Ozerova (1983), the concentration of mercury (elemental mercury, Hg⁰) reflects the origin of natural gas. Dai (1992) showed that Hg⁰ concentrations are greater than 700 ng/m³ in coalbed gas and less than 500 ng/m³ in oil-type gas. However, Hg⁰ concentrations vary significantly within a single gas field (Liu, 2013). As a result, the Hg⁰ concentration alone is an imprecise estimate of the natural gas source.

Mercury is commonly found in oil and gas (including shale gas) and mainly exists in the form of elemental mercury, which provides a basis for the study of mercury isotopes. There are seven stable isotopes of mercury: ¹⁹⁶Hg (0.15%), ¹⁹⁸Hg (9.97%), ¹⁹⁹Hg (16.87%), ²⁰⁰Hg (23.10%), ²⁰¹Hg (13.18%),²⁰²Hg (29.86%), and ²⁰⁴Hg (6.87%). The relative mass difference between the isotopes was up to 4%. Mercury is the only identified heavy metal element that can undergo mass-dependent fractionation (MDF) and mass-independent fractionation (MIF). A series of important natural processes involved in the geochemical cycle of mercury, such as volatilization and evaporation (Lefticariu et al., 2011), oxidation/reduction (Foucher et al., 2009), microbial methylation/demethylation (Feng et al., 2010; Yin et al., 2013), photoreduction reactions (Bergquist and Blum, 2007; Kwon et al., 2020), and natural hydrothermal systems [(Smith et al., 2008; Stetson et al., 2009), can lead to significant mercury isotope mass-dependent fractionation. Photoreaction is the main natural process leading to the mass-independent fractionation of mercury stable isotopes (Bergquist and Blum, 2007; Kwon et al., 2020), where mercury isotopes are essential in tracing mercury sources and geochemical processes. Many studies have been conducted on mercury isotopes in organic matter correlated to oil and gas, such as algae and phytoplankton (Perrot et al., 2012; Tsui et al., 2012), invertebrates (Blum et al., 2014), lake sediments, marine sediments (Feng et al., 2010; Ma et al., 2013), terrestrial plants (Sun et al., 2017; Wang et al., 2017), lichens (Carignan et al., 2009), peat (Enrico et al., 2017; Enrico et al., 2016; Shi et al., 2011), coal (Biswas et al., 2008; Lefticariu et al., 2011; Sun et al., 2016), and soil (Foucher et al., 2009; Yin et al., 2013). The Hg isotopic ratios show promise as a method for distinguishing different sources of natural gas. Stable isotopes of mercury in oil-type gas and coalbed gas have been studied (Washburn et al., 2018; Tang et al., 2019); however, stable isotopes of mercury in shale gas have not yet been reported.

Shale gas, as a clean, efficient, and low-carbon unconventional natural gas, has multiple effects such as economy, society, and environment. The development and utilization of shale gas help achieve the goals of “carbon peak” and “carbon neutrality,” which has become an important part of the energy structure of the world. The research object of this study is the existing shale gas in the Zhaotong Block of the Sichuan Basin. The mercury in shale gas was collected on-site, whereby we analyzed the mercury content and stable isotope composition of mercury in the samples. Further, we compared the mercury stable isotope compositions of oil-type gas and coalbed gas in previous studies. As such, we summarized, herein, the general characteristics of the mercury isotope composition of shale gas, and discussed the main material sources and exploration indicative significance of shale gas.

Mercury Capture and Analysis of Mercury Content and Mercury Isotope in Shale Gas

Geological Overview of Sampling Sites

The sampling site is located in the YS108 Block, Zhaotong National Shale Gas Demonstration Area, Sichuan Basin (Figure 1). The block is one of the first national shale gas demonstration zones in China and is an important part of commercial shale gas in China (Chen et al., 2019). The YS108 block is located in Gongxian County and Junlian County, Yibin City, Sichuan Province, adjacent to the Changning shale gas block, which is structurally located at the southern edge of the low-steep fold belt in the southern Sichuan Tai Depression and adjacent to the northern depression of Yunnan and Guizhou (Figure 1A). The main gas-producing zone is the upper Wufeng Formation of the Ordovician and lower Longmaxi Formation of Silurian, characterized by a buried depth of 2,000–2,500 m, and it is the main zone for shale gas horizontal well development in the block (Figure 1B). As a whole, it belongs to a set of black siliceous shale and organic-rich black carbonaceous shale deposited in marine deepwater shelf subfacies, with large sedimentary thickness (30–40 m), high organic matter abundance, thermal evolution degree (TOC ≥2.0%, Ro: 2.0–3.5%), adequate gas content (3.0–4.6 m³/t), adequate reservoir performance (Φ: 1.56–5.27%), and high compressibility (brittleness index: 44%–78%). The target formation has the characteristics of overpressure (pressure coefficient 1–1.9), and is a favorable shale gas development formation (Dai et al., 2014; Wang et al., 2016).

FIGURE 1

FIGURE 1. Structural map of Zhaotong Demonstration Zone (A) and YS108 Block (B) [Figure A is modified according to Xu et al. (2019), and Figure B is modified according to Huang et al. (2019)]. In Figure B, the red wells are the sampling sites, and the horizontal wells of the related wells are drawn. The yellow and gray wells are other wells in the block.

Sample Collection and Processing

The mercury in the shale gas of seven gas accumulation wells from three gas accumulation platforms in Block YS108 of Zhaotong National Shale Gas Demonstration Zone in Sichuan Basin was collected on-site, denoted as H1-3, H1-6, H3-1, H3-2, H11-1, H11-2, and H11-3 gas accumulation wells. A total of 37 samples of mercury capture fluid from shale gas were collected.

Mercury in shale gas is captured by potassium permanganate (KMnO₄) and sulfuric acid (H₂SO₄) mixture: Hg⁰ in shale gas was oxidized to ionic form mercury and captured and retained in acidic potassium permanganate solution (Figure 2) by taking advantage of the strong oxidation and super absorption of mercury in acidic potassium permanganate solution, such that the acidic potassium permanganate solution was recovered as a sample for mercury content and mercury isotope analysis. In previous studies (Tang et al., 2019), we used three series of acid potassium permanganate cylinders to capture mercury in oil-type gas and coalbed gas, but laboratory simulations and mercury isotope tests found that Hg⁰ is mainly enriched in the first impinger (the percentage of mercury content is 76%–97%), and the isotopic composition of total mercury is consistent with that of the solution of the first impinger. Therefore, we simplified the mercury capture device for shale gas, and the main body of the mercury capture device was composed of three impingers (Environmental Supply Company, United States, 500 ml for each sampling bottle) in series. The first impinger was an empty bottle for separating water vapor in shale gas, ensuring the concentration of acidic potassium permanganate mixture in the second impinger, mercury capture efficiency, and mercury capture time. The second impinger contained 100 ml of 4% (w/v) KMnO₄ and 1% (v/v) H₂SO₄. Hg⁰ in shale gas was oxidized to ionic mercury and captured and retained in an acid potassium permanganate solution. The acid potassium permanganate solution was recovered as a sample for mercury content and mercury isotope analysis in shale gas. The third impinger contained approximately 100 mg of discolored silica gel, which was used to absorb the water vapor attached to the remaining gas to prevent its impact on the subsequent gas flowmeter. The three impingers were fixed in a cold-water tank.

FIGURE 2

FIGURE 2. Mercury capture device for shale gas [Description: 1. Sampling port; 2. Empty bottles; 3. Impact bottle with 4% (W/V) KMnO₄+1% (V/V) H₂SO₄ solution; 4. Impact bottle with color-changing silicone; 5. Gas flowmeter].

To ensure the authenticity of mercury capture in shale gas, the used chemical reagents, drugs, impingers, and their connecting tubes need to be processed in advance, which requires a low blank value of mercury. Potassium permanganate was purchased from the United States (mercury content is <0.002 ng/ml), sulfuric acid is eminently pure (mercury content is <0.004 ng/ml), and the impinger and its connecting parts are borosilicate glass bottles purchased from the United States and have been subjected to high-temperature treatment in a muffle furnace. The purchased PTFE pipe was used to connect the pipe from the shale gas wellhead to the impinger. Before sampling, the entire sampling device was directly flushed with the original natural gas of the shale gas wellhead for approximately 3–5 min, and the acid potassium permanganate mercury-capturing mixture prepared on-site was quickly filled and connected to the whole device. Each sample captures 1 m³ of mercury in shale gas, which ensures the representativeness of the capture shale gas and enriches enough mercury to meet the requirements of mercury isotope analysis. During the sampling process, the color of the mercury capture liquid should always be purple. Once it becomes colorless, the sampling should be immediately stopped. The acidic potassium permanganate mixture was recovered as the sample, and the volume of the mixture and gas flowmeter data were recorded. After each sampling, the mercury capture solution was recovered, and the volume was recorded with a measuring cylinder and transferred to a borosilicate glass bottle. Approximately 0.5 ml of potassium dichromate solution (30%, w/v) was immediately added, sealed, numbered, and transported back to the laboratory for testing.

Analysis of Mercury Content

The mercury content of the captured mercury from acid potassium permanganate was determined by using the RA-915 M mercury meter and its liquid attachment. After the standard curve was plotted depicting the mercury standard solution, approximately 10 ml of acidic KMnO₄ solution sample was added to the centrifuge tube, and then approximately 0.5 ml of NH₂OH-HCl solution with a mass volume fraction of 15% was slowly added with a pipette. Shaking resulted in the captured mercury solution to be colorless and transparent, where 5 ml of the sample solution was added with a pipette to a 20% (w/v) SnCl₂ solution foaming bottle open on the left side of the liquid attachment. At this time, Hg²⁺ in the sample was reduced to Hg⁰ and was pumped by the instrument to the right foaming bottle containing 30% NaOH solution (the purpose was to remove the volatile acidic gas in the sample and prevent the host from being corroded). Hg⁰ was sent to the host of the mercury analyzer to determine the mercury content. The sampling process was powered by a constant-speed gas pump in the liquid attachment, and the average value of each sample was taken as the final result after two measurements (relative deviation less than 10%).

Analysis of Mercury Isotope

The mercury isotopic composition in the mercury capture solution was determined using multi-collector inductively coupled plasma mass spectrometry (MC-ICP-MS, Neptune Plus) at the Institute of Geochemistry, Chinese Academy of Sciences according to previous methods (Tang et al., 2017; Tang et al., 2019). The mercury concentration of the sample of mercury capture liquid to be diluted before the determination of mercury isotope was 0.5 ppb. A certain amount of mercury captured solution samples (calculated according to mercury content) with known mercury content were taken into a 15-ml centrifuge tube. At most, 0.5 NH₂OH-HCl (30%, w/v) was dropped into the solution to make it colorless and transparent, and the solution was then diluted to 15 ml with secondary distilled water. The mercury concentrations of the process standard solution NIST SRM3133 and the external standard NIST SRM3177 at the time of injection were configured to be 0.5 ppb. The mass fractionation of mercury isotopes is usually expressed by the thousandth fractionation (‰) of δ^XXXHg, where δ refers to the deviation between the sample mercury isotope ratio and the standard mercury isotope ratio (Blum and Bergquist, 2007). For better data comparison, NIST SRM3133 Hg is usually used as the standard (Blum, 2012). The calculation formula is as follows:

${\delta }^{\mathrm{XXX}}\mathrm{H}\mathrm{g}(‰)=\left[\raisebox{1ex}{$\left(\raisebox{1ex}{${}^{\mathrm{XXX}}\mathrm{H}\mathrm{g}$}\!\left/ \!\raisebox{-1ex}{${}^{198}\mathrm{H}{\mathrm{g}}_{\mathrm{s}\mathrm{a}\mathrm{m}\mathrm{p}\mathrm{l}\mathrm{e}}$}\right.\right)$}\!\left/ \!\raisebox{-1ex}{$\left(\raisebox{1ex}{${}^{\mathrm{XXX}}\mathrm{H}\mathrm{g}$}\!\left/ \!\raisebox{-1ex}{${}^{198}\mathrm{H}{\mathrm{g}}_{\mathrm{N}\mathrm{I}\mathrm{S}\mathrm{T}3133}$}\right.\right)$}\right.-1\right]\times 1000(1)$

where XXX refers to 199, 200, 201, 202, and 204, respectively. The mass-independent fractionation of mercury isotopes is represented by Δ^xxxHg (‰), which refers to the deviation between the measured and theoretical values. It is specifically calculated according to the following formula (Blum and Bergquist, 2007):

${\mathrm{\Delta }}^{199}\mathrm{H}\mathrm{g}={\mathrm{\delta }}^{199}\mathrm{H}\mathrm{g}-\left({\mathrm{\delta }}^{202}\mathrm{H}\mathrm{g}\ast 0.2520\right)(2)$

${\mathrm{\Delta }}^{200}\mathrm{H}\mathrm{g}={\mathrm{\delta }}^{200}\mathrm{H}\mathrm{g}-\left({\mathrm{\delta }}^{202}\mathrm{H}\mathrm{g}\ast 0.5024\right)(3)$

${\mathrm{\Delta }}^{201}\mathrm{H}\mathrm{g}={\mathrm{\delta }}^{201}\mathrm{H}\mathrm{g}-\left({\mathrm{\delta }}^{202}\mathrm{H}\mathrm{g}\ast 0.7520\right)(4)$

Results and Discussion

Mercury Content in Shale Gas

The mercury content of shale gas in the YS108 block of the Zhaotong demonstration area is shown in Figure 3 and Supplementary Table S1 (Supporting Information). The mercury content of 37 shale gas samples ranged from 171 to 2,906 ng/m³, with an average of 1,551.08 ± 787.08 ng/m³ (n = 37, 1 SD). The mercury content in shale gas detected by Han et al. (2021) in the southern Sichuan Basin (mean: 1,420 ng/m³) is consistent with that detected by Han et al. (2021), which is significantly lower than the average mercury content in the coal-formed gas of the Shanshan oilfield (Li, 2020) and the oil-type gas of the Liaohe oilfield, and higher than that in the coalbed gas of the Hebi Coal Mine (Tang et al., 2019). The overall mercury content demonstrates coal-formed gas > oil-type gas > shale gas > coalbed gas, but the mercury content varies by one to several orders of magnitude.

FIGURE 3

FIGURE 3. Mercury content in different types of natural gas.

Natural gas can be divided into organic and inorganic gases according to genetic type, among which organic gas includes oil-type gas mainly from marine or lacustrine sapropelic and sapropelic to humic-type organic matter and oil-type gas that forms crude oil, and coal-formed gas mainly from terrestrial humic-type organic matter (Ni et al., 2019; Li et al., 2012a). According to the lithology of the reservoir, natural gas can be divided into coal-formed gas (including coalbed gas generated by coal seams and coal-formed gas, produced by coal seams but migrated to other coal seams or other reservoirs), shale gas, and tight sandstone gas (Liu, 2018). It is generally believed that mercury in natural gas is mainly derived from organic matter in gas source rocks or crude oil. During the thermal evolution of organic matter into hydrocarbons, mercury accumulates with natural gas in the form of volatile components. The mercury accumulation capacity of terrestrial organic matter (such as coal and dispersed humus) is relatively strong (Liu et al., 2020; Li et al., 2012b). The mercury content is relatively high; therefore, the mercury content in coal-formed gas is generally higher than that in oil-type gas, and the organic matter content in shale gas is relatively lower than that in coal-formed gas and oil-type gas; therefore, the mercury content is also relatively low (Figure 3). The mercury content in coalbed gas is the lowest in mine no. 6 of the Hebi coal mine, which is related to the low mercury content in the coal seam. The mercury content of shale gas in the YS108 block of the Zhaotong demonstration area is also lower than the average mercury content (6,840 ng/m³) of over-mature marine gas (also oil-type gas) in the Sichuan Basin (Han et al., 2021).

In addition, the mercury content may be related to the state of natural gas occurrence. After the formation of alkane gas, it is stored in micron- or nanometer-sized reservoir pores in the form of free, adsorption, and dissolution (Gong et al., 2014). Mercury migrates with free natural gas in the form of steam during hydrocarbon generation. Coalbed gas and shale gas are self-generation and self-accumulation modes, respectively. About 70%–95% of coalbed gas exists in the adsorption state (Liu, 2018), the adsorption state of shale gas accounts for approximately 20%–85% of the total gas (Curtis, 2002; Montgomery et al., 2005), and the adsorption of shale gas at the Wufeng-Longmaxi Formation in Sichuan Basin accounts for approximately 40% (Li et al., 2018). Coal-formed gas and oil-type gas are mainly in the free state, CBM is mainly in the adsorption state, and shale gas has free and adsorbed gas. Therefore, the mercury content of coal-formed gas and oil-type gas is generally higher than that of shale gas and CBM, and the mercury content of CBM is the lowest. The mercury content in shale gas varies greatly between wells (Supplementary Table S1) mainly because of the maldistribution of organic matter in the source rock (Tian et al., 2014; Wu et al., 2016; Deng and Sun, 2019).

Characteristics of Mercury Isotope Composition in Shale Gas

The mercury isotopic composition of shale gas in the Zhaotong YS108 block is shown in Figure 4. The Δ¹⁹⁹Hg values (relative to NIST 3133) are positive (0.02‰–0.39‰), with an average of 22‰ ± 0.08‰ (n = 37,1 SD), which is consistent with the Hg-MIF values (Δ¹⁹⁹Hg: +0.05‰–+0.15‰, with an average of 0.12‰ ± 0.03‰) of the Wufeng-Longmaxi black shale in the Sichuan Basin reported by Shen et al. (2019), indicating that there is no evident mass-independent fractionation of mercury isotopes during gas formation from gas source rock to shale gas owning to the lack of exposure to light in the underground gas formation process leading to the MIF of the mercury stable isotope. Although some scholars have reported that the stable isotopes of mercury produce very small Hg-MIF under dark conditions (Zheng and Hintelmann, 2010) (Blum et al., 2014; Tang et al., 2019), photochemical reduction is believed to be the most important process causing Hg-MIF. Therefore, it is considered that the mass-independent fractionation of the stable isotope of mercury does not occur in the underground dark environment of hydrocarbon generation, and the information characteristics of the mass-independent fractionation of the stable isotope of mercury in the organic matter of the gas source rocks are retained, which also indicates the main organic matter types of the gas source rocks. The δ²⁰²Hg values in shale gas range from −1.68‰ to −0.04‰, with an average of −0.87‰ ± 0.31‰ (n = 37, 1 SD), and the δ²⁰²Hg values in shale gas of the same formation range from −2.5‰ to −1.0‰ with an average value of −1.36‰ ± 0.34‰, n = 22, 2 SD) (Shen et al., 2019), but relatively positive, indicating that shale gas is more enriched in heavy isotopes of mercury than its source rock. Laboratory studies have demonstrated that many redox reactions involving Hg cause MDF including abiotic and biotic processes (Kritee et al., 2018; Wiederhold et al., 2010; Jiskra et al., 2012; Zheng et al., 2019); therefore, this study does not describe all geochemical processes that contribute to the mass fractionation of mercury isotopes.

FIGURE 4

FIGURE 4. Characteristics of shale gas Δ¹⁹⁹Hg and δ²⁰²Hg (A) and Δ¹⁹⁹Hg and δ ²⁰¹Hg (B): The ellipse in Figure A shows the mean values of Δ¹⁹⁹Hg and δ²⁰²Hg (inner ellipse) and 95% confidence level (outer ellipse).

It is generally believed that the nuclear volume effect (NVE) (Schauble, 2007) and magnetic isotope effect (MIE) (Buchachenko et al., 2007) are the main mechanisms for the generation of mercury stable isotope mass-independent fractionation (MIF), and the two can be effectively distinguished by the ratio of Δ¹⁹⁹Hg/Δ²⁰¹Hg. The ratio of MIFΔ¹⁹⁹Hg/Δ²⁰¹Hg caused by NVE was greater than 1.6, such as the mercury-thiol complex (Δ¹⁹⁹Hg/Δ²⁰¹Hg = 1.54) and mercury reduction process caused by abiotic action under dark conditions (Δ¹⁹⁹Hg/Δ²⁰¹Hg = 1.5–1.6) (Wiederhold et al., 2010; Zheng and Hintelmann, 2010) and elemental mercury volatilization (Δ¹⁹⁹Hg/Δ²⁰¹Hg = 2.0) (Estrade et al., 2009). The ratio of Δ¹⁹⁹Hg/Δ²⁰¹Hg of MIF caused by MIE is 1–1.36, such that the photoreduction reaction of Hg^II_aq Δ¹⁹⁹Hg/Δ²⁰¹Hg = 1.0 (Bergquist and Blum, 2007; Zheng and Hintelmann, 2009) and the photodegradation of methylmercury Δ¹⁹⁹Hg/Δ²⁰¹Hg = 1.36 (Bergquist and Blum, 2007). The mercury in the studied shale gas sample Δ¹⁹⁹Hg/Δ²⁰¹Hg = 1.001 ± 0.18 (Figure 4B) indicates that the main mechanism for the occurrence of MIF in the mercury isotope in shale gas is MIE caused by Hg^II_aq photoreduction reaction, which also indicates that the mercury in shale gas undergoes the photoreduction reaction of Hg²⁺ in water before deposition.

Comparison of Mercury Isotope Composition in Shale Gas, Oil-Type Gas, and Coalbed Gas

There are relatively few studies on mercury isotopes in natural gas (Tang et al., 2019; Washburn et al., 2018), and the development and utilization of mercury isotopes in shale gas in recent years have not been reported. Figure 5 summarizes the results of shale gas and Tang et al. (2019) on mercury isotopes in oil-type gas and coalbed gas.

FIGURE 5

FIGURE 5. Comparison of mercury isotopic composition in different types of natural gas: the data of oil-type gas and coalbed gas are quoted from the literature (Tang et al., 2019).

The Δ¹⁹⁹Hg of shale gas in the Zhaotong YS108 block is positive and similar to that of oil-type gas in the Liaohe oilfield and Zhongyuan oilfield, and δ²⁰²Hg is also consistent (Figure 5), indicating that they have similar sources of mercury and types of organic matter. The Δ¹⁹⁹Hg range of shale gas in the Zhaotong YS108 block is 0.02‰–0.39‰, with an average of 0.22‰ ± 0.08‰ (n = 37, 1 SD). The gas source rock is deep-sea sedimentary shale, and its hydrocarbon-forming organic matter is mainly rich in algae and low phytoplankton, and algae is the only confirmed lower plant with positive Δ¹⁹⁹Hg at present (Figure 6, Perrot et al., 2012; Tsui et al., 2012). This is similar to the positive value in Δ¹⁹⁹Hg of Ordovician black shale (Gong et al., 2017), Ordovician argillaceous limestone (Shen et al., 2019; Gong et al., 2017), and modern marine sediments (Gehrke et al., 2009; Ogrinc et al., 2019), which is also consistent with the positive value for Δ¹⁹⁹Hg of marine shale gas and continental oil-type gas (Tang et al., 2019), but it is significantly different from the negative Δ¹⁹⁹Hg value of coalbed gas and modern higher plants (Figure 6). Therefore, the isotopic composition of mercury in shale gas most likely retains that of hydrocarbon-forming algae and lower plankton. In fact, approximately 90% of the mercury in the ocean originates from atmospheric mercury deposition (Mason et al., 2012). Most of the mercury exists in the form of dissolved Hg²⁺ ions or other mercury oxides that are easily soluble in seawater. Algal organic matter is rich in −SH, which is thermodynamically favorable for the rapid uptake and accumulation of inorganic Hg²⁺ in seawater (Fitzgerald and Lamborg, 2014; Le Faucheur et al., 2014), allowing algae to reach a higher mercury concentration level. After algal death, the deposition of algal debris transfers mercury from surface waters to deeper waters and sediments, and the process is analogous to a “biological pump” of mercury (Hirner et al., 1990; Li et al., 2012b; Verburg et al., 2014). The average Hg content in algal organic matter in Arctic lake sediments before 1800 was as high as 159–776 μg/kg (n = 24), which is 2–39 times higher than that in the sediments, demonstrating the “biological pump” mechanism of algal cleaning of mercury in seawater (Outridge et al., 2019). Shale gas reservoirs in the Wufeng-Longmaxi Formation in the study area are mainly formed in a shelf retention environment with limited water circulation and are dominated by black carbonaceous shale and siliceous shale with rich organic matter content (Wu et al., 2016). Organic components such as planktonic algae, acritarch, bacteria, and animal detritus such as graptolite, chitin, and sponge needles have been observed in shales (Tengger et al., 2017; Nie et al., 2019). Ma et al. (2020) conducted hydrocarbon-generating thermal simulation experiments on shales and graptolites with different maturities in the upper Ordovician and lower Silurian and found that hydrocarbon-rich and fat-rich organic matter such as algae and acritarch are the main organic matter for shale gas generation. With an increase in burial depth and formation temperature, mercury in the complex and adsorbed state of algae organic matter gradually desorbed under thermal action and migrated to oil and gas reservoirs or oil reservoirs in the form of steam (Peng et al., 2019). Therefore, the Δ¹⁹⁹Hg information in shale gas and the Δ¹⁹⁹Hg of the main hydrocarbon-forming organic matter—algae (0.17‰–0.64‰, with an average of 0.39 ± 0.21‰, n = 4,1 SD) (Perrot et al., 2012; Tsui et al., 2012)—showed no significant difference (t-test, p > 0.05) and all values are positive, which also indicates that Δ1⁹⁹Hg in marine crude oil is similar to that of algae.

FIGURE 6

FIGURE 6. Mercury isotopic composition information of shale gas and its hydrocarbon generating medium Δ¹⁹⁹Hg comparison, in which I-1 is Ordovician black shale [quoted from literature (Gong et al., 2017)], I-2 is Ordovician argillaceous limestone [quoted from literature (Shen et al., 2019; Gong et al., 2017)], I-3 is modern marine sediment [quoted from literature (Gehrke et al., 2009; Ogrinc et al., 2019)], I-4 is Arctic seawater [quoted from literature (Štrok et al., 2015)], I-5 is planktonic algae [quoted from literature (Perrot et al., 2012; Tsui et al., 2012)], II-1 is shale gas (this study), II-2 is continental oil-type gas [quoted from literature (Tang et al., 2019)] II-3 refers to coalbed gas [quoted from literature (Tang et al., 2019)], III-1 refers to leaves [quoted from literature (Demers et al., 2013; Zheng et al., 2016)], III-2 refers to litter on the Qinghai Tibet Plateau [quoted from literature (Wang et al., 2017)], and III-3 refers to freshwater sediments [quoted from literature (Gantner et al., 2009; Donovan et al., 2013; Sherman and Blum, 2013)].

The oil-type gas in the Liaohe and Zhongyuan oilfields is formed by the evolution of source rocks in continental lakes or delta sedimentary environments. The source rocks, herein, are continental dark mudstone and shale (E2-3s) of the Eocene Shahejie Formation. The sources of mercury in lakes and oceans are significantly different: atmospheric mercury deposition is the main entry pathway of mercury in pelagic sediments, while lake or delta sedimentary environments receive various forms of mercury from various sources, such as mercury dissolved in catchment runoff, tributaries, and adsorbed and fixed in particulate matter and sediments (Fitzgerald and Lamborg, 2014). There exist both higher plant and animal sources of mercury, as well as planktonic sources of mercury such as algae in lake and river delta sedimentary environments (Outridge et al., 2007).

The Δ¹⁹⁹Hg values of freshwater sediments have both positive and negative values (Figure 6 III-3; Donovan et al., 2013; Gantner et al., 2009; Sherman and Blum, 2013), but in the continental oil-type gas, we studied Δ¹⁹⁹Hg as positive (Figure 6 II-2, Tang et al., 2019). As mentioned earlier, algae are the only lower plants with positive Δ¹⁹⁹Hg that have been confirmed so far, and the continental oil-type gas and mercury present in them are mainly derived from source rocks. Therefore, it is believed that the main hydrocarbon-forming organic matter of continental oil-type gas cannot come from higher plants but are mainly derived from plankton such as algae that self-accumulate in the sedimentary environment of the source rock. This also makes the Δ¹⁹⁹Hg between shale gas in the Zhaotong YS108 block and oil-type gas in the Liaohe and Zhongyuan oilfields (Δ¹⁹⁹Hg:0.06‰–0.30‰, mean 0.17‰ ± 0.06‰, n = 24, 1 SD) positive, showing no significant difference. The above results also indicate that the main organic matter of continental crude oil is abundant algae and other plankton in lake or delta environments, and Δ¹⁹⁹Hg is positive. Therefore, continental oil and gas exploration can find algae-rich target strata or delineate the target strata with a positive Δ¹⁹⁹Hg value. For example, most of the planktonic and algal fossils have been found in the source rocks of the continental oilfields in China, such as the Shengli, Maling, and Wangchang oilfields (Liu, 2018).

The Δ¹⁹⁹Hg of shale gas in the Zhaotong YS108 block, oil-type gas from the Liaohe oilfield, and Zhongyuan oilfield is significantly different from that of coalbed gas in mine no. 6 of the Hebi Coal Mine (Figure 5). The coal seam in mine no. 6 of the Hebi coal mine is the continental coal seam of the Permian fluvial and lacustrine facies. The main coal-forming organic matter was terrestrial higher plants, and the Δ¹⁹⁹Hg was negative (Figure 6). Therefore, the mercury Δ¹⁹⁹Hg (−0.19‰ to −0.01‰, −0.11‰ ± 0.06‰, n = 7, 1 SD) in coalbed gas was also negative. Δ¹⁹⁹Hg is significantly different from that of shale gas and oil-type gas.

Conclusion

The mercury content of marine shale gas in the YS108 block of Zhaotong demonstration area ranges from 171 to 2,906 ng/m³, with an average of 1,551.08 ± 787.08 ng/m³ (n = 37,1 SD). The Δ¹⁹⁹Hg values of mercury isotopes range from 0.02‰ to 0.39‰, with an average of 0.22‰ ± 0.08‰ (n = 37, 1 SD), and the δ²⁰²Hg values range from −1.68‰ to −0.04‰, with an average of −0.87‰ ± 0.31‰ (n = 37, 1 SD), which are significantly different from the Δ¹⁹⁹Hg and δ²⁰²Hg values of coalbed gas, but not significantly different from the Δ¹⁹⁹Hg and δ²⁰²Hg values of terrestrial oil-type gas. We can use it as an indicator to search for algae-rich continental strata or delineate the strata with positive Δ¹⁹⁹Hg as exploration targets.

Data Availability Statement

The original contributions presented in the study are included in the article/Supplementary Material, Further inquiries can be directed to the corresponding authors.

Author Contributions

ST: conceived the idea for this study and provided manuscript guidance; GZ: assisted in sample collection and manuscript revision; YD and ST: data analysis, manuscript writing and revision; XF, HZ and PL: helped supervise the projects. All authors listed have made a contribution to the work and approved it for publication.

Funding

This research was supported by the National Natural Science Foundation of China (41573006 and 41372360) and the CNPC (China National Petroleum Corporation) Scientific Research and Technology Development Project (Grant No. 2021DJ05).

Conflict of Interest

Author GZ was employed by the company PetroChina.

The remaining authors declare that the research was conducted in the absence of any commercial or financial relationships that could be construed as a potential conflict of interest.

Publisher’s Note

All claims expressed in this article are solely those of the authors and do not necessarily represent those of their affiliated organizations, or those of the publisher, the editors, and the reviewers. Any product that may be evaluated in this article, or claim that may be made by its manufacturer, is not guaranteed or endorsed by the publisher.

Acknowledgments

We thank Gaoen Wu of State Key Laboratory of Environmental Geochemistry, Chinese Academy of Sciences, for assistance in measuring Hg isotopes. We thank the editor and reviewers for their thoughtful comments, which significantly improved the quality of this paper.

Supplementary Material

The Supplementary Material for this article can be found online at: https://www.frontiersin.org/articles/10.3389/feart.2022.809418/full#supplementary-material

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