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The effect of salinity on source rock formation and its control on oil content in the shales in the Hetaoyuan Formation from the Biyang Depression, Nanxiang Basin, central China Taohua He, Shuangfang Lu, Wenhao Li, Tan Zhaozhao, and Xinwen Zhang Energy Fuels, Just Accepted Manuscript • DOI: 10.1021/acs.energyfuels.8b01075 • Publication Date (Web): 24 May 2018 Downloaded from http://pubs.acs.org on May 24, 2018
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The effect of salinity on source rock formation and its control on oil content in the shales in the Hetaoyuan Formation from the Biyang Depression, Nanxiang Basin, central China Taohua He 1, 2, Shuangfang Lu 1*, Wenhao Li 1**, Zhaozhao Tan 1, 2, Xinwen Zhang 3 1
Research Institute of Unconventional Petroleum and Renewable Energy, China University of
Petroleum, Qingdao 266580, China; 2
School of Geosciences, China University of Petroleum(East China), Qingdao, Shandong 266580,
China; 3
Research Institute of Exploration and Development, Henan Oilfield Company, SINOPEC,
Zhengzhou 450000, China.
ABSTRACT: A total of 75 shale samples from the Biyang Depression, were analyzed with Rock-Eval, total organic carbon (TOC), organic maceral, and gas chromatograph-mass spectrometry (GC-MS) techniques to reveal the effect of salinity on source rock formation and its control on oil content. Based on the diversities in salinity and redox conditions reflected by the gammacerane /αβ C30 hopane (G/H) ratio, the pristine / phytane (Pr/Ph) ratio, and the extended tricyclic terpane ratio [ETR= (C28 + C29) tricyclic terpane / Ts)], three types (T1, T2 and T3) of shales were identified, which deposited in the brackish condition (G/H ratio < 0.3), the semi-saline condition (G/H ratio = 0.3-0.6), and the saline condition (G/H ratio > 0.6), respectively. The comparisons among T1, T2 and T3 shales revealed that the salinity had a significant effect on the paleoproductivity of the lacustrine system. Most algae thrive in semi-saline conditions (T2) but they are restrained in saline conditions (T3) so that moderate salinity conditions (G/H ratio = 0.3-0.6) are most conducive to the accumulation of algae organic matter (AOM). Although they have similar thermal maturity (0.6%~1.1% vitrinite reflectance) and kerogen type (type II), the T1, T2 and T3 shales were developed in different reducing environments indicated by the Pr/Ph ratio and contained variable abundance of organic matter, resulting remarkable *&** Corresponding authors at: Research Institute of Unconventional Oil & Gas and Renewable Energy, China University of Petroleum (East China), Qingdao 266580, China. E-mail:
[email protected], Tel: 86-18661856596(S. Lu); E-mail:
[email protected], Tel: +86 15253220962(W. Li).
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differences in the preservation condition of AOM and the shale oil content within the T1, T2 and T3 shales. The classification and evaluation criteria of the shale oil resource were performed according to three categories based on oil content (S1) and TOC values. It was revealed that the T1, T2 and T3 source rocks were mainly distributed among these areas of the potential, enriched and ineffective shale oil resources, respectively, suggesting that shales developed in semi-saline environments deserve to be the most desirable target of shale oil exploration and development at present. Thus, this work may help related industry practitioners acquire valuable information from lacustrine shale systems. Key words: salinity, paleoproductivity, redox conditions, shale oil resources, Biyang Depression
1. Introduction Due to the shortage of conventional oil and gas resources and the increasingly prominent contradiction between the supply and demand of petroleum, shale oil in lacustrine source rocks, reported to have a substantial, recoverable amount of 5 billion tons1, is currently a frontier and a highlighted field in the petroleum industry and has received continued attention in recent years.2-6 This type of resource mainly distributed in large depressions has been widely found in many lacustrine sedimentary basins, including the Bohai Bay Basin, the Songliao Basin, the Junggar Basin, the Ordos Basin, the Nangxiang Basin, the Santanghu Basins and the Jianghan Basin.1,4-5,7-11 Moreover, substantial progress has been made in the generation of shale oil.1 It is widely believed that higher abundance of total organic carbon (TOC >2%), more advantageous Kerogen type (Type II to Type I), and medium maturity (Ro = 0.6% ~ 1.3%) were conducive to oil generation in shales; this has been frequently evidenced by typical oil-bearing shale basins or depressions, such as the Williston Basin, the Maverick Basin, the Fort Worth Basin, the Jiyang Depression, the Dongpu Depression and the Biyang Depression.12, 13 In addition, oil-rich shale has been found to be of algal origin14, and a wide variety of models of lacustrine shale formation have been provided to interpret the distribution of shales and to predict lacustrine ACS Paragon Plus Environment
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petroleum resources, including the tectonic subsidence-driven shale formation model15, the organic facies-driven shale formation model16,
17
, the depositional
environment-driven shale formation model18-20 and other models driven by two or more of the above factors21-23. Shale oil is held in source rock with high organic matter (OM) abundance, a more advantageous kerogen type, and appropriate maturity. Thus, the oil content in shale is largely dependent on algal organic matter (AOM), which in turn is affected by the salinity of the water body. Few studies have focused on the effect of salinity on the lacustrine OM-rich shale formation and its control on the distribution of shale oil, although some scholars have mentioned that it could lead to obvious variations of biota and could have a significant effect on the preservation of OM in lacustrine systems15, 24-28. Zhang et al. believed that increased salinity could provide a strong anoxic environment, which was conducive to OM preservation found by the geochemical analysis of shales in the Dongpu Depression27. Liu et al. argued that the enrichment degree of OM first increased and then decreased with increasing water salinity by investigating the OM content in lacustrine shales in the Qaidam Basin from the perspective of paleosalinity28. Thus, in this study, the effect of salinity on lacustrine shales was discussed, based on organic geochemistry data of cores from the third member of the Hetaoyuan Formation (Eh3) in the Biyang Depression in the Nanxiang Basin. The organic enrichment mechanisms as well as the potential of shale oil resources in this layer were also revealed.
2. Geological setting The Biyang Depression, covering an area of approximately 1000 km2 (Figure 1A), is located in the eastern Nanxiang Basin, a late Mesozoic-Cenozoic terrestrial graben-like basin formed within the folded basement of the Qinling Orogen during the Late Yanshanian. This depression has a dustpan-shape, with two deep fracture faults developed to its southwest and southeast. The two fault systems caused a maximum subsidence of 7000-8000 m and dominated the formation and evolution of the whole depression concluding three secondary structural units which are northern slop belt,
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southern steep slope belt and central deep sag, respectively. This area experienced a main rifting period in the Paleogene, resulting in a continuously depositional system consisting of the Yuhuangding Formation (Ey), Dacangfang Formation (Ed), Hetaoyuan Formation (Eh) and Liaozhuang Formation (El) from bottom to top (Figure 1B). Among these Paleogene formations, the third member of the Hetaoyuan Formation (Eh3) can be divided into eight beds on the basis of seismic sedimentation data and cores, and was mainly deposited in a deep lacustrine environment29 (Figure 1B). The mudstones and shales are widely developed in the second and third beds of the Eh3 (Eh32 and Eh33), which were the main exploration targets for shale oil resources in the Biyang Depression6, 30. Additionally, the Eh32 and Eh33 beds are believed to have considerable petroleum potential for shale oil because of their large thicknesses (Figure 1B), their very wide distribution, their low-moderate thermal maturity (Ro = 0.6% ~ 1.1%), their high organic carbon content (up to 8.5%) and their better organic matter type (type II).31 There was a frequent change between humid and dry climates32, which may have caused a fluctuation in the water salinity during the period of the Eh32 and Eh33 depositions, and an obvious heterogeneity within the shale intervals. Therefore, the influence of the salinity change should be taken into consideration and made clear before the exploration of shale oil in the Biyang Depression, Nanxiang Basin.
3. Sample and methods A total of 75 core samples were collected from the Eh32 and Eh33 in the BY1, B94 and C2 wells marked in Figure 1A in the central Biyang Depression, Nanxiang Basin, where shale oil was widely distributed. Paleosalinity was considerably changed with frequent climate fluctuations between wet and arid conditions during the period of the Eh32 and Eh3 depositions.3, 30 These changes were recorded in the shales and were revealed by salinity parameters within them, which made the Biyang Depression appropriate to study the effect of salinity on the lacustrine shales. The samples were ground to a 200 mesh size for the TOC test and the Rock-Eval analysis by using a LECO CS-600 carbon/sulfur analyzer and Rock-Eval VI analyzer,
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respectively. The organic maceral measurements were conducted on a fluorescence microscope LABORLUX 12 POL microphotometer (MPV-3) under a relatively stable temperature of (23 ±2) °C during the experiment. The representative pictures are presented in Figure 2. All the shale samples were chosen for quantitatively calculating chloroform bitumen “A” by extracting powdered samples in a Soxhlet apparatus with dichloromeane (CH2Cl2) for 72 h. Then, the extracts were separated into saturates, aromatics, resins (NSO) and asphaltenes. The saturated fractions were analyzed using a SHIMADZU GC-2010Plus equipped with an FID and a DM-5MS capillary column (60 m, 0.25 mm i.d., and 0.25 µm film thickness), and a SHIMADZU GC-2010/GC-2010Plus-MS OP2010 Ultra apparatus, in which the MS operated in electron impact ionization mode at an electron energy of 70 eV and an ion source temperature of 230°C. Other detail information of the specific instrument parameters and the experimental procedures have been documented in the published literature33. These experiments were performed at the Guangzhou Institute of Geochemistry, Chinese Academy of Sciences. The results of the TOC, “A” and Rock-Eval analyses are shown in Table 1, while those of the GC and GC-MS analyses are presented in Table 2.
4. Results and Discussion 4.1. Classifications of shale rock on the salinity Gammacerane
is
believed
to
be
the
product
of
the
reduction
of
tetramethylalcohol34, mainly derived from bacterivorous ciliates35. This ciliate thrives at the interface between the oxic and anoxic zones in stratified water columns. Thus, the abundant gammacerane, presented by the gammacerane index [gammacerane/αβ C30 hopane (G/H)] > 0.11, indicates the presence of a stratified water column.36 High ratios of G/H also have been found in high salinity environments, suggesting that G/H becomes one of the classic parameters reflecting salinity stratification of the water columns during the period of source rock deposition.37, 38 In the extended tricyclic
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terpane ratio [ETR= (C28 + C29) TT/ Ts)] proposed by Holba et al.39, G/H and Pr/Ph ratios have been individually used or combined together to classify source rocks and crude oil according to the differences in salinity and redox conditions.15,
40
This
function was also applied in this study. Three types (T1, T2 and T3) of shale rocks were determined in the lacustrine shale beds in the Biyang Depression, Nanxiang Basin (Figure 3), based on the differences in salinity and redox conditions during the period of their depositions. The T1 shales have G/H, ETR and Pr/Ph ratios ranging from 0.10 to 0.30, 0.05 to 1.66 and 0.37 to 0.64, respectively, with the averages of 0.18, 1.14 and 0.50, respectively. These values indicate a brackish and weakly reducing condition during the period of its deposition. The Pr/Ph ratio decreases obviously with the increase in the G/H ratio (Figure 3), meaning that the redox conditions are directly controlled by salinity in the water body. The T2 shales display higher G/H ratios and ETR ranging from 0.30 to 0.60 and 0.33 to 3.14, with averages of 0.54 and 1.68, respectively, but have a lower Pr/Ph ratio ranging from 0.35 to 0.54, with an average of 0.43. These values suggeste that the T2 shales were deposited in a reductive semi-saline water condition. In contrast to the T1 and T2 shales, the T3 shales were characterized by the highest G/H ratio (>0.6) but by a relatively stable ETR (averaging approximately 1.78) and Pr/Ph ratio (averaging approximately 0.46), revealing a saline and strongly reducing environment during the formation of the T3 shales. It is shown that when the G/H ratio is < 0.6, the ETR increases with the increase in the G/H ratio (Figure 3), which is a frequently used salinity parameter. This result indicates that the ETR is an effective indicator of salinity during the sedimentary period of source rocks in a lacustrine environment, as reported by Kruge et al.41, De Grande et al.42 and Hao et al.15, 43. However, this phenomenon cannot continue when the G/H ratio is higher than 0.6 in a hyper-saline condition (Figure 3). According to the classification results of shales from Table 1 and Table 2, there is a strong heterogeneity in the distribution of the T1, T2 and T3 shales in the Eh32 and Eh33. The Eh33 contains T1, T2 and T3 shales in proportions of 8.33%, 75.00% and 16.67%, respectively. However, the Eh33 contains T1, T2 and T3 shales in proportions of 68.25%, 19.05% and 12.70%, respectively. ACS Paragon Plus Environment
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This result means that the T1 shales were mainly developed in the Eh33 and that the T2 shales were mainly deposited in the Eh32, while the T3 shales were formed in both the Eh32 and Eh33, although in small proportions ( 0.6 in lacustrine systems. A similar relationship between the input of algae and another salinity parameter (ETR) is also presented in Figure 7. The data of the S/H and C23TT/C30H ratios show that T2 shales have the highest S/H and C23TT/C30H ratios, averaging 0.43 and 0.09, respectively. This result indicates that the algae were largely developed during the T2 shales deposition, which was in accordance with numerous lamalginites and telalginites observed in the organic micrographs from the T2 shales. In contrast, the T3 shales displayed the lowest S/H and C23TT/C30H ratios, averaging 0.18 and 0.06, respectively. This result shows the paucity in the algae developed during the period of T3 shales deposition, which was consistent with a few lamalginites and telalginites identified in the organic micrographs from the T3 shales. The S/H and C23TT/C30H ratios from the T1 shales are not higher than those of the T2 shales but are also not lower than those of the T3 shales, indicating a moderate contribution from the algae. Notably, the higher reducing environment, inferred from the low Pr/Ph ratio (< 0.5), is mainly associated with high salinity (G/H ratio >0.3), enhancing the preservation of AOM. There was a relative increase in algae as discussed above, resulting in the highest concentration of AOM occurring in this source rock (T2 shales) deposited under the semi-saline environment (G/H ratio =0.3-0.6). In summary, the moderate salinity conditions not only promote the increase in algae but also strengthen the preservation in lacustrine systems. 4.3. Shale oil resources in different shale rocks The amounts of chloroform bitumen “A” and the pyrolyzed hydrocarbon (S1) are the first two geochemical indices widely applied to directly reflect the oil content within shales.54 There was a profoundly similar correlation between “A” or S1 versus the G/H ratio and the S/H or C23TT/C30H ratios versus the G/H ratio (Figure 6b-c; ACS Paragon Plus Environment
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Figure 8b, e). This result suggests that the T2 shales, developed in semi-saline condition with an increase in algae, have the highest oil content. The T3 shales, however, are deposited under a saline environment with a paucity of algae and display the lowest oil content since the algae are the main source materials for generating oil. Considering the latest proposed classification and the evaluation criteria of shale oil10, 54
, we performed a classification and evaluation of shale oil in the T1, T2 and T3
shales, combined with the TOC value. The TOC is not only the main source of generating hydrocarbon, but is also the main medium for hydrocarbon adsorption.54 Three segments were obviously identified between the “A” or S1 versus TOC (Figure 8c, f): (1) “A” or S1 maintains a stable high value segment (S1>1.8 mg/g, “A”>0.6 %) when TOC is high (>2.0 %), indicating that the generated oil reaches various conditions of residual oil in shales when TOC meets a threshold (2.0% in this example). If TOC gets higher, the surplus oil is expelled. Therefore, such shale is rich in the most abundant oil content or enriched resources deserving further shale oil exploration and development at present. (2) “A” or S1 maintains a stable low value segment (S1
