Significance of gypsum-salt rock series for marine hydrocarbon accumulation

Petroleum Research 2 (2017) 222e232

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Significance of gypsum-salt rock series for marine hydrocarbon accumulation Wenhui Liu a, b, c, *, Heng Zhao d, e, Quanyou Liu a, b, Bing Zhou a, b, Dianwei Zhang a, b, Jie Wang a, b, Longfei Lu a, b, Houyong Luo a, b, Qingqiang Meng a, b, Xiaoqi Wu a, b a

State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, SINOPEC, Beijing 100083, China Petroleum Exploration & Production Research Institute, SINOPEC, Beijing 100083, China Northwest University, Shaanxi 710069, China d Lanzhou Center for Oil and Gas Resources, Institute of Geology and Geophysics, Chinese Academy of Sciences, Gansu 730000, China e University of Chinese Academy of Sciences, Beijing 100049, China b c

a r t i c l e i n f o

a b s t r a c t

Article history: Received 25 November 2016 Received in revised form 21 April 2017 Accepted 26 April 2017

With further exploration and research, the gypsum-salts rock series as good caprocks attracted a lot of attention. The gypsum-salt rock series played an important role during migration, preservation and trapping of hydrocarbons. Recently, major breakthroughs have been continuously made in marine petroleum exploration of gypsum-salt rock series in the eastern Ordos Basin, the central Tarim Basin and the western Sichuan Basin in China, and the high-evolution and low-abundance gypsum-salt rock series as hydrocarbon source rocks become possible. Besides research advances in the reservoirecaprock assemblage of gypsum-salt rock series, development and hydrocarbon-generation potential of source rocks in the gypsum-salt rock series were well studied in terms of source-rock development environment and hydrocarbon generation mechanism. Results showed that the gypsum-salt rock series, including high-evolution and low-TOC gypsum-salt rock series in China, could be regarded as good source rocks. This understanding was a breakthrough to previous traditional viewpoint that low-TOC gypsum-salt rock series could not act as effective hydrocarbon sources. The key to understand hydrocarbon-generation mechanism was that abundant and high-quality hydrocarbon-generation materials, large amount of hydrocarbon generation and conversion in geological history, and hydrocarbongeneration materials occurred in the form of carboxylates, were developed in the high-evolution and low-TOC gypsum-salt rock series. © 2017 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-nc-nd/4.0/).

Keywords: Gypsum-salt rock series Hydrocarbon generation Source rock Sedimentary environment Reservoir Caprock

1. Introduction Gypsum-salt rock was a kind of evaporate which primarily consisted of gypsum, anhydrite and gypsum metahydrate with a certain amount of saline minerals, clay minerals, organic matter and iron oxides (Shen et al., 2000; Zhang et al., 2014; Zhuo et al., 2014). The gypsum-salt rock series occurred spatially with gypsum-salt rock, was developed during the gypsum salt deposition period, pre-salt and post-salt depositional periods, and the epigenetic modification period posterior to formation of the gypsum-salt rock series. Basically, it referred to sedimentary series

* Corresponding author. State Key Laboratory of Shale Oil and Gas Enrichment Mechanisms and Effective Development, SINOPEC, Beijing 100083, China. E-mail address: [email protected] (W. Liu). Peer review under responsibility of Petroleum Research.

influenced by gypsum salt geochemical environment, and included marine gypsum-salt rocks, marine carbonate rocks and minor amount of clastic rocks. Besides controlling development of highquality hydrocarbon caprocks, the gypsum-salt rock series played some special roles in development and modification of source rocks and carbonate rock reservoirs. Around the world, formations of many large hydrocarbon reservoirs were closely associated with the gypsum-salt rock series, and the gypsum-salt rockecarbonate rock association was an important hydrocarbon accumulation assemblage in the world. Numerous gypsum-salt rock sedimentary basins were developed in China, among which the Tarim Basin, Ordos Basin and Sichuan Basin were marine basins. As continuous breakthroughs made in the exploration of oil and gas in Leikoupo Formation in the western Sichuan Basin, the Ordovician pre-salt hydrocarbon reservoirs in the eastern Ordos Basin, and Well Zhongshen 1 and Well Zhongshen C1 in Tazhong area of Tarim

https://doi.org/10.1016/j.ptlrs.2017.04.002 2096-2495/© 2017 Chinese Petroleum Society. Publishing Services by Elsevier B.V. on behalf of KeAi. This is an open access article under the CC BY-NC-ND license (http:// creativecommons.org/licenses/by-nc-nd/4.0/).

W. Liu et al. / Petroleum Research 2 (2017) 222e232

Basin, potential roles of the gypsum-salt rock series in marine hydrocarbon accumulation had drawn high attention. Because the gypsum-salt rock was a core factor for formation and evolution of the gypsum-salt rock series, only the gypsum-salt rock was discussed in this paper in detail. The gypsum-salt rocks had tight, plastic and mobile features, and were long regarded as good caprocks. However, researches on oilesalt paragenetic basins showed that 46% of pay beds was below salt-bearing strata, 41% was above salt-bearing strata and 13% was within salt-bearing strata (Zhang and Tian, 1998). Therefore, it was speculated that besides as good caprocks, the gypsum-salt rocks might play an important role in hydrocarbon accumulation. Further studies in recent years showed that the gypsum-salt rock series played important roles in the generation, migration, preservation and trapping processes of oil and gas (Busson, 1992; Jin et al., 2006, 2010; Hao et al., 2015). Nonetheless, researches on potential and mechanism of hydrocarbon generation from the gypsum-salt rock series was still very insufficient at present, that directly influenced hydrocarbon exploration and resource assessment of marine gypsum-salt rock series. In this paper, relevance of the gypsum-salt rock series with hydrocarbon formation and accumulation was studied, and research advances in reservoirecaprock assemblage of the gypsum-salt rock series were summarized; but importantly, development and hydrocarbon-generating potential of source rocks in the gypsum-salt rock series were well investigated from perspectives of source rock development environment and hydrocarbon generation mechanism.

2. Formation environment and depositional model of the gypsum salt Theories on the origin of gypsum salts had been developed for a long time, and genetic models such as sand bar, desert, subkha salification, deepwater and deep basin, dried deep basin and high mountain deep basin had been established successively, and promoted development of gypsum salt genesis theory (Yuan and Xie, 1963; Yuan et al., 1983; Zhang, 1992). According to current studies, the gypsum salt has two genesis types, such as the evaporation genesis, the deep brine genesis, of which the evaporation-derived gypsum salts was formed from evaporation and deposition of paleo-seawater in the closed to semi-closed arid environments (e.g., marine tidal flat, lagoon, bay and coastal subkha), this type of gypsum salts were widely distributed with small thickness. The deep brine-derived gypsum salts were formed from precipitation of mantle fluids which intruded upward along large deep fractures and then directly formed without undergoing large-scale evaporation process; hence, formation of this type of gypsum salt was not related with the arid climate, and its depositional range controlled by active tectonic zones was restricted, but thickness was often extremely large (Zhang et al., 1999; Zhao et al., 2007); thus, this type of gypsum salts derived from deep brine could be regarded as good caprocks and main source materials of late salt tectonic transformation, and it also might contain relative high content of organic matter under certain conditions and had good hydrocarbon-generation potential (Yuan and Qin, 2001). But the deep brine-derived gypsum salts greatly differed from typical evaporite in sedimentary cycle, lithologic sequence and distribution characteristics, and it not belonged to the marine gypsum-salt rock series. In this paper, the evaporation-genetic gypsum-salt rocks, including some gypsum-salt rocks which were formed from deep brine and underwent large-scale evaporation process, would be focused in this study.

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2.1. Sedimentary environment of gypsum salts Evaporation-derived gypsum-salt rocks were formed from evaporation, concentration and crystallization of brine during the middle and late periods of basin development, its origin was generally related to restricted basin, subsidence rate, deposition rate and extreme arid climate (Yuan et al., 1983; Jin et al., 2006), and source materials of the gypsum-salt rock mainly included seawater, deep brine and overland runoff (Gao et al., 2009). The gypsum-salt rocks were mostly formed during the basin transformation period. From perspective of sequence stratigraphy, the gypsum-salt rocks mostly occurred in the highstand systems tracts of the secondorder sequence of fast transgression or slow regression, and mainly were distributed in the late period of the highstand systems tracts (Zhou et al., 2011). The restricted basin caused continuous salt accumulation without free communication with external water, and the water in the basin was thus fully evaporated. The gypsumsalt rocks were primarily developed in the basins with subsidence rate less than deposition rate; under such condition, the sedimentary environment of lacustrine/sea basin would change from the semi-closed lagoons to the closed saline lake environment, resulting in abrupt increase of salt concentration of basin water and massive gypsum-salt rock deposition (Kirkland and Evans, 1981). The climate condition was also a main constraint for gypsum-salt rock deposition, and arid climate condition made evaporation effect greater than recharging effect, so that the salt concentration kept increasing and the gypsum-salt rocks deposited; but in a transient humid climate, the clastic sediments were developed. The gypsum-salt rocks deposited under the reduction or oxidation condition with a high water salinity (greater than 140‰) and a pH value greater than 7.8 (Gao et al., 2009). In the stable deepwater environment, the surface water was evaporated to form high-density brine which would settle down under gravity and displace lower-density deep brine, then the stratified brine was formed. The surface water had the low salinity, the deep water had the very high salinity which was up to the saturation concentration of the gypsum-salt rock, while the middle halocline had the very variable water salinity. With high dissolved oxygen and low salinity, the surface water was suitable for survival of euryhaline and halophilic plankton. The deep water was relatively tranquil, and basically did not exchange with the surface water, thus lack of free oxygen kept the deep water in the reduced state (Degens and Stoffers, 1976). The stratified brine led to high biomass yield in the surface water and anoxic reduction environment in the deep water, that were favorable for formation of highquality source rocks (Jin et al., 2008). As continuous evaporation, the water salinity kept increasing and precipitated carbonate minerals, gypsum minerals and salt rock minerals in an ascending order of solubility. Such the gypsum-salt rocks had the stable developed horizons and lack of exposure markers, its horizontal distribution exhibited the planar zone, i.e., of mudstone, carbonate rock and gypsum-salt rock occurrence sequentially from margins to the center (Bao et al., 2004). Due to flood water and decrease of salt source materials induced by climate change, the stratified brine would be damaged to form clastic sediments, and poor anoxic condition was not favorable for preservation of organic matter (Fig. 1). Greatly influenced by external factors, the shallow-water environment could not form the stratified water in general, but would also precipitate saline minerals due to intense evaporation. Such type of gypsum-salt rocks was poorly stratified, mainly occurred in nodular, ptygmatic or scattered shapes with exposure markers and onshore purple-red muddy sediments; horizontally, it was developed in the land side and exhibited the banded distribution which was parallel with shoreline (Li et al., 2012).

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Fig. 1. Depositional model of stratified brine and depositional model of clastic rock during the flood period (modified from Jin et al., 2008) showing the stratified brine was favorable for formation of high-quality source rocks and the unstratified brine was not favorable for preservation of organic matter. (a) The depositional model of the stratified brine; (b) the depositional model of clastic rock during the flood period.

2.2. Depositional model of gypsum salts Based on gypsum salt origin, sedimentary facies and abundance of organic matter, Busson (1992) classified the gypsum salts into three types in the basinal scale: the gypsum-salt rock deposition in the basin center, the gypsum-salt rock deposition in the basin margin and the gypsum-salt rock deposition in the continental shelf (or in the deeper basin of the epicontinental sea) (Fig. 2). The gypsum-salt rock deposition in the basin center was a common depositional model for gypsum salts. During the aggradation stage, the evaporites were deposited with increase of water salinity; carbonates were formed in highstand areas, and towards depression of the basin center, it gradually transited to large amount of sulfates; horizontally, these sediments occurred in the annular distribution pattern from the basin margin to the basin center, and were characterized by deepwater evaporation of large thickness and large area. From the view of the sedimentary facies, the salinity gradient increased towards the basin center; the evaporation in the basin center was mostly related to reefs and shoals; TOC was high in the basin center and the gypsum-salt rocks were good caprocks, so this kind of the basin was very rich in hydrocarbon. Gypsum-salt rock deposition in the basin margin was related to deep brine which intruded upward in the backreef framework of the basin margin, and the centrifugal salinity gradient occurred. The basin center was occupied by high-TOC marine sediments in the unsaturated state, and the organisms were dominated by plankton and nekton communities; while organic reefs in the basin margin were developed towards land and evolved into lagoon facies and terrigenous clastic facies. The surface water flew continuously towards the hypersaline area in the basin margin, and this ocean current to the subbasin of backreef evaporite could bring persistent organic matter supply, and thus the gypsum-salt rocks in the basin margin had very high TOC. The deep brine that intruded

upward in the backreef framework provided sufficient source materials of gypsum salt for the basin margin, and increased stability of the stratified brine, thus this kind of the basin was also rich in hydrocarbon. The salinization of gypsum-salt rock deposition on the continental shelf (or deep basins of epicontinental seas) was lateral and synchronous with depositional isolation, and due to shallow water, the stratified water could not be formed. This type of gypsum-salt rocks had a low TOC, thus was not suitable to act as hydrocarbon source rocks. The depositional environment (including tectonic environment, sedimentary environment, climate environment) and depositional model of gypsum-salt rocks influenced type and content of organic matter, lithologic sequence, distribution area, physical and chemical conditions in the gypsum-salt rock series, so as to control hydrocarbon generation, accumulation, reservoiring and preservation of the gypsum-salt rock series, and was the key factor to study hydrocarbon accumulation potential role of the gypsum-salt rock series. 3. Caprock characteristics of the gypsum-salt rocks The caprock was a key factor for formation and preservation of hydrocarbon reservoir, and the conventional effective caprock was mainly shale and gypsum-salt rock (Grunau, 1981). According to statistics on caprocks of large oil and gas fields and reservoirs in the world (Fig. 3), the shale caprocks accounted for more than 80% of total distribution area of caprocks, but it only sealed 22% of global oil reserves; the gypsum-salt caprocks took only 8% of total distribution area of caprocks, but it controlled 55% of global hydrocarbon reserves and was regarded as good caprocks for hydrocarbon reservoir preservation (Jin et al., 2006). The statistics of 13 major gas-bearing basins in China showed that the gypsumsalt rocks were developed in four basins, and 165 gas fields were

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Fig. 2. Depositional model of gypsum-salt rocks (modified from Busson, 1992) showing three types of the gypsum-salt rock deposition were distributed in different depositional environments. (a) The gypsum-salt rock depositional model of the basin center showing that the gypsum-salt rocks were deposited in deepwater with large thickness and large distribution area; (b) The gypsum-salt rock depositional model of the basin margin showing that deposition of the gypsum-salt rocks were related to deep brine which intruded upward in the backreef. (c) The gypsum-salt rock depositional model of the continental shelf showing that the salinization of gypsum-salt rock deposition on the continental shelf was lateral and synchronous with depositional isolation.

Fig. 3. Property comparison of the gypsum-salt caprocks (data from Jin et al., 2006). (a) Statistics of capping hydrocarbon reserves of different lithologies in the world showing that although the distribution area was small, but the gypsum-salt caprocks controlled more than half of global hydrocarbon reserves in the world; (b) Statistics of major petroliferous basins with and without the gypsum-salt rocks in China showing that the gypsum-salt rocks were developed in four basins, and number of gas fields with the gypsum-salt rocks accounted for 40% of total gas field in China, the proved gas reserves with the gypsum-salt rocks accounted for 36% of total gas reserves in China.

discovered, it accounted for 40% of total gas field in China; the proved gas reserves were 1571.86
109 m3, and accounted for 36% of total gas reserves in China (Jin et al., 2006). Evaluation of hydrocarbon caprocks included microscopic and macroscopic aspects. The former was mainly to study the caprock

sealing mechanism, while the latter was to study the caprock lithology, thickness, distribution area and the matching between sealing property and reservoiring conditions (Grunau, 1981; Zhou et al., 2012). Early studies on the gypsum-salt caprocks mainly focused on microscopic evaluation, the sealing mechanisms

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included petrophysical sealing, overpressure sealing and hydrocarbon concentration sealing (Grunau, 1981; McIntyre, 1988; Zhou et al., 2012). According to research on caprocks in the world, Grunau (1981) pointed out that evaporites (such as gypsum-salt rocks) were ideal caprocks. Early studies on sealing mechanisms of the gypsum-salt caprocks mainly focused on petrophysical sealing (Peach, 1991). The gypsum-salt rocks had tight lithology and very high displacement pressure, which were the most fundamental and general sealing mechanism. The overpressure sealing, one of sealing mechanisms, was studied very early (Osborne and Swarbrick, 1997); gypsum dehydration in conversion to anhydrite, hydrocarbon generation of the gypsum-salt rock series and unbalanced compaction all might result in pore fluid overpressure which played an important role in hydrocarbon reservoir formation and preservation. Compared with petrophysical sealing mechanism and pressure sealing mechanism, the hydrocarbon concentration sealing (Zhang, 1991) was discussed later, it prevented natural gas from diffusion and migration in the form of molecular phase, but this sealing mechanism only occurred in caprocks which had ability of hydrocarbon generation. The gypsum-salt rock series had good hydrocarbon-generation potential, thus it played an important role in hydrocarbon concentration sealing. In addition, the gypsum-salt rocks had very high brine saturation, it could prevent entry of external fluids and oxidative damage of organic matter, and thus prevented gas diffusion effectively (Li et al., 2007; Zhou et al., 2012). The early microscopic evaluation could not reflect the sealing characteristics of caprocks, so the later microscopic evaluation began to focus on studies of caprock effectiveness in deformation and accumulation processes, including studies on mechanical property of caprocks, matching between caprock sealing property and reservoiring condition. The plasticity and fluidity of the gypsum-salt rocks were very strong, and varied with temperature, pressure and buried depth conditions. The gypsum-salt rocks occurred as the solid or weak plastic state at the normal temperature and pressure, but when the buried depth was more than 500 m, it began to reach its softening point; when the buried depth was more than 3000 m, the gypsum-salt rocks had extremely mobility, and under such the condition, brittle fractures was not easy to occur, thus the gypsum-salt caprocks and hydrocarbon reservoirs all were well preserved (Zhao et al., 2007; Jin et al., 2010). Besides, fluidity of gypsum-salt rock was favorable for occurrence of diapirism to form domes, thus hydrocarbon reservoirs were blacked laterally. Moreover, the gypsum-salt rock series has good hydrocarbon-generation potential, and could be as source rocks and caprocks, so it had the unique advantage in matching between the caprock sealing evolution and the hydrocarbon-generation history of source rock. Therefore, whether in the microscopic sealing mechanism or the macroscopic effectiveness, the gypsumsalt rocks were the ideal caprocks with the best quality. However, dissolution and rheology of the gypsum-salt rocks were the main factors to damage the caprocks (Zhou et al., 2012). 4. Reservoir characteristics of the gypsum-salt rocks In the traditional theory, the gypsum salt could not be regarded as hydrocarbon reservoirs due to tight lithology; but recent studies showed solution vugs in the gypsum salt, and intercrystalline pores formed in the transition from gypsum to anhydrite, resulted in that the gypsum salt had potential to store hydrocarbons. Besides, development of the gypsum salt not only was favorable for pore preservation of its underlying strata, but also promoted occurrences of dolomitization and thermal sulfate reduction (TSR), thus leading to form secondary pore such as intercrystalline pores and solution vugs and improve reservoir property of the gypsum-salt

rock series effectively (Gong and Zeng, 2003; Wang et al., 2005; Zhao et al., 2007). 4.1. Primary pores Thermal conductivity of the gypsum-salt rocks was 2e3 times than that of the general lithology, leading to rapid heat diffusion of its underlying strata and slow down diagenetic process, thus pores in the pre-salt strata could be well preserved (Wang et al., 2005; Zhao et al., 2007). Additionally, pore fluid overpressure due to own characteristics of the gypsum-salt rocks restrained the compaction to some extent, leading to undercompaction of underlying strata which largely contributed to preservation of primary pores in the pre-salt strata (Zhao et al., 2007). 4.2. Secondary pores 4.2.1. The gypsum-salt rocks Gypsum was a soluble component of the gypsum-salt rock series, and the water-rock interaction was an important factor to damage the gypsum-salt rock, but at the same time, the solutionvugs reservoirs could also be formed. The gypsum salt was easy to be hydrated in case of water, and then anhydrites were converted into gypsums; during the gypsum dissolution process, the gypsumkarst breccias were formed. Fluids played a very important role in watererock interaction, and pore fluids in marine gypsum-salt rock series could be divided into neutral fluid, alkaline fluid, acidic fluid, and hydrocarbon fluid. The simulated dissolution test of the gypsum-salt rocks showed that fluid nature had little effect on dissolution rate, though dissolution rates were slightly higher in acidic fluids such as CO2 and organic acids. Furthermore, temperature and pressure were important factors to influence the gypsum salt dissolution; the dissolution rate of the gypsum-salt rock first rose and then fell evidently with increase of temperature and pressure, and turning points of temperature and pressure varied with sample property and medium (Cao, 2014). Therefore, the gypsum-salt rocks in the mid-shallow strata were more easily dissolved to form reservoirs, while the gypsum-salt rocks in the deep strata was more prone to be well preserved as caprocks (Hong et al., 2015). According to reaction position and fluid nature, dissolution of the gypsum-salt rock could be divided into epigenetic dissolution, interlayer dissolution and deep-hydrothermal dissolution. 4.2.2. The carbonates The presence of the gypsum salt also could make adjacent carbonate rocks more susceptible to dissolution, and form carbonate reservoirs with secondary pores. In the hot arid areas, the gypsum deposition in the supratidal zone led to Mg/Ca ratios of interparticle water in surface sediments or surface water up to 20 or even higher (Feng, 1989), and such Mgrich brine directly might make dolomitization in carbonate rocks (Zhu et al., 2014). Therefore, the gypsum-salt precipitation promoted dolomitization to form secondary pores, laying a foundation for late reservoir development. A majority of high-quality marine carbonate reservoirs in China had the close relation with sulfate reduction (Zhu et al., 2014; Hao et al., 2015), while the gypsum salts provided source materials for sulfate reduction reactions (TSR and BSR). In China, marine carbonate rocks were mainly distributed in the Lower Paleozoic, its deep-buried depth led to high paleo-geotemperature to make organic acids decomposed, so H2S and CO2 from sulfate reduction (TSR and BSR) should be main acidic media for carbonate dissolution, and were extremely corrosive to carbonate rocks, so this kind of acidic media was the main factor to improve reservoir property.

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Fig. 4. Distribution of Oligocene evaporite and high-quality source rocks in the western Qaidam Basin (Jin et al., 2008) showing that high-quality source rocks (TOC>1%) occurred with sulfate or chloride minerals. (a) Distribution of Oligocene evaporite in the western Qaidam Basin; (b) Distribution of Oligocene source rocks with different TOC in the western Qaidam Basin.

Moreover, TSR reaction needed supply of SO42, thus this reaction was accompanied with dissolution of the gypsum salt, that further improved reservoir property. Additionally, studies showed that the sulfate reduction was closely related with dolomitization, SO42 related with sulfate reduction removal would lead to dolomitization, while SO42 related with sulfate dissolution introduction would accelerate dolostone dissolution (Huang et al., 1996, 2008). 5. Characteristics of source rocks and hydrocarbongeneration potential The continental oil generation theory proposed by Chinese researchers in 1980s provided the theoretical support for successful exploration of hydrocarbon in the continental basins, and accordingly, large freshwater lakes were mostly favorable for formation of high-quality source rocks (Huang et al., 1984; Jin et al., 2008). However, recent studies indicated that high-quality source rocks (TOC>1%) in China's continental basins intergrew with carbonate, sulfate or chloride minerals to variable extents (Fig. 4). For example, Member 1 of Cretaceous Qingshankou Formation and Member 1 of Nengjiang Formation were major source rocks of Songliao Basin, and recent studies showed that these source rocks might be related with the salinized lacustrine basin which was formed by marine transgression (Li and Pang, 2004; Hou et al., 2000; Ye et al., 2000). Source rocks of Ordos Basin were mainly distributed in Member 2 and Member 3 of Triassic Yanchang Formation, and had high content of carbonate rocks which might be product of salinized lake. Paleogene Qianjiang Formation and Xingouzui Formation were major source rocks of low-maturity oil in Jianghan Basin, these two formations were typically deposited from saltwaterebrackish water (Ma et al., 2002; Jin et al., 2008). In fact, in China's MesozoiceCenozoic inland basins, whether the eastern faulted basins or western depression basins (e.g., Bohai Bay Basin, Subei Basin, Jianghan Basin, Pearl River Delta Basin, Qaidam Basin), the except the coal-bearing strata, the high-quality source rocks were all related to the salinized lake basins rather than freshwater basins as previously believed (Jin and Zha, 2000; Ye et al., 2000; Jin et al., 2008). Studies showed that the marine gypsum-salt rocks as important source rocks in hydrocarbon-rich basins, were extensively distributed in Iran, Oman, France, Mexico and other Persian Gulf countries (Curial et al., 1990; Edgell, 1991; Hussain and Warren, 1991). Thought continuous breakthroughs of hydrocarbon exploration had been made in China's marine gypsum-salt rock

series in recent years, source of hydrocarbon were still unclear; the marine gypsum-salt rock series was depositional products of typical saltwater environment, its hydrocarbon-generation mechanism and potential were the key to resolve the source-rock problem in the marine basin, and thus was worthy of further i investigation. 5.1. Relationship between deposition process of gypsum-salt rock series and development of hydrocarbon source The deposition process of the gypsum-salt rock series was controlled by multiple factors including tectonic evolution of basin, climate change, relative sea level change, material supply and so on. Integrated effect of such multiple factors determined deposition characteristics of the gypsum-salt rock series and their relationship with development of hydrocarbon source. Hydrocarbon source formed before and after the depositional period of gypsum-salt rock series were the same as the conventional hydrocarbon source rocks, which had been well studied systematically (Liu et al., 2010, 2012; Qin et al., 2014) and would not be involved in this paper. Herein, formation of special hydrocarbon source formed during the depositional period of the gypsum-salt rock series would be discussed. Different lithologic sequences were formed in different filling periods, and in many oil and gas fields, variations in tectonic subsidence, climate and eustasy before and after the depositional period of the gypsum-salt rock series led to change of lithologic sequences and form conventional source rocks. For these source rocks, the gypsum-salt rock series could be as caprocks or reservoirs. For example, dolomite and shale primarily developed in the Sinian Dengying Formation and the Lower Cambrian Jiulongdong Formation (Qiongzhusi Formation) in Weiyuan area of Sichuan Basin, are the main gas sources of Weiyuan gasfield (Dai, 2003; Chen et al., 2013); afterward, as seawater became more saline and shallower, the gypsum-salt rocks of tidal flat and supratidal subkha were formed in the Lower Cambrian Longwangmiao Formation, that was the important caprocks for Weiyuan gasfield (Ran et al., 2008; Zhang, 2011). The traditional understanding was that organic matter yield was very low in the hypersaline environment and was difficult to form high-quality source rocks (Ungerer et al., 1990). Compared with the normal marine environment, in in the hypersaline water environment where the gypsum-salt rock series were formed, the biological species were less, but product fluxes of the species were very

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large (Kirkland and Evans, 1981). According to researches of modern evaporation environment (modern saline lake), the species of organisms decreased with increase of salinity, but the biological yield normally increased with increase of salinity (Copeland and Jones, 1965). For example, in the Columbia saline lake, the biological yield of halophilic microorganisms was up to 1690 g/(m2$a), total bacteria count in the lake water was up to (65.2e905)
103/L, and the biomass of halophiles in the lake water was 1542 g/L (Liu et al., 2013a). In addition, good anaerobic condition of the gypsum-salt rock series was favorable for preservation of organic matter, and some cases of the gypsum-salt rock series as source rocks had been found worldwide (Curial et al., 1990; Jin and Zha, 2000; Li and Pang, 2004; Jin et al., 2008). In summary, the gypsum-salt rock series could be regarded as hydrocarbon source rocks. 5.2. Biological assemblage characteristics and hydrocarbongeneration materials Whether the traditional shale source rocks or the source rocks of carbonate rocks and gypsum-salt rock series, these source rocks themselves had no hydrocarbon-generation potential, but instead, its associated biological communities were the true source of organic matter for hydrocarbon generation. Therefore, researches on biological assemblage characteristics and hydrocarbongeneration materials of source rocks were the key to evaluate hydrocarbon-generation potential. 5.2.1. Hydrocarbon source formation before and after the depositional period of the gypsum-salt rock series Before and after the depositional period of the gypsum-salt rock series, hydrocarbon source was formed in the normal seawater salinity environment with the same biological assemblage characteristics and hydrocarbon-generation materials of the conventional marine source rocks. According to studies, the hydrocarbongeneration organisms in marine high-quality source rock mainly

had three types: (1) planktonic algae (such as acritarchs, siliceous mallomonas and cyanobacteria), (2) benthos (such as siliceous algal mats, siliceous algal sporangia and primitive linear-leaved plants), (3) fungus (such as calcareous fungi hyphae, siliceous bacteria and thiobacteria). The planktonic algae was equivalent to Type-I kerogen, that mainly contributed to hydrocarbon generation and conversion rate; the benthos was equivalent to Type-II kerogen, that mainly contributed to organic carbon; the fungus of hydrocarbon-generation potential was related with kerogen type of primitive organisms, and could improve hydrocarbon-generation capability (Liu et al., 2010, 2012). 5.2.2. Hydrocarbon source formation during the depositional period of the gypsum-salt rock series During the depositional period of the gypsum-salt rock series, hydrocarbon source was formed in the hypersaline water environment with the special biological assemblage characteristics and hydrocarbon-generation materials. Studies on the typical sedimentary environment of modern gypsum-salt rock (modern saline lake) showed that green algae and cyanobacteria were major biological communities in the hyposaline water, while halophiles were dominant biological community in the hypersaline environment (Sammy, 1983; Gocke et al., 2004). The species in the formation environment of the gypsum-salt rocks was less than that in the normal environment, and mainly included cyanobacteria, Dunaliella salina, phototrophic thiobacteria, halophilic archaea, Artemia salina and fungi (Fig. 5), but product fluxes of these biotas were tremendous (Barbe et al., 1990; Warren, 2010). In the north lake of Zabuye saline lake in Tibet, a large amount of red halophilic algae (Dunaliella salina) were developed (Zheng et al., 1985). 5.2.3. Hydrocarbon-generation materials The gypsum-salt rock series had very high biological yield and anaerobic condition in favor of organic matter preservation, which should have a high TOC; but a majority of gypsum-salt rock strata had a low TOC, therefore, the gypsum-salt rock series as

Fig. 5. Biological communities in different salinity water bodies. (a) Typical survival salinity range of halotolerant organisms showing the biota species in the formation environment of the gypsum-salt rocks mainly included cyanobacteria, Dunaliella salina, phototrophic thiobacteria, halophilic archaea, Artemia salina and fungi; (b) Major biota species and survival salinity range of biological communities in modern marine salt pools (Barbe et al., 1990; Warren, 2010) showing product fluxes of these biotas were tremendous. Vi represented inflow volume, Vo represented outflow volume which included evaporated volume and reflux volume.

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hydrocarbon source was still in doubt. Type of high-quality organic matter in the gypsum-salt rock series, evolutionary characteristics of organic carbon in the geological time and hydrocarbongeneration materials occurred in the carboxylate form were key factors to make breakthroughs in understanding. 5.2.3.1. TOC of the gypsum-salt rock series. At present, a majority of the gypsum-salt rock strata discovered in the world had a low TOC, mostly smaller than 1%. For example, the Holocene to Pleistocene evaporites in Texas to western New Mexico in the United States, had an average TOC of about 0.6%; the Upper Permian evaporites in Fore-Sudetic Monocline in Poland had TOC of 0.1e0.7%; the greywhite gypsum rocks in Member 4 of Leikoupo Formation in Sichuan Basin had TOC less than 0.2%, and the salt rocks in Ordovician Majiagou Formation in Ordos Basin had TOC less than 0.3%. Only a small number of gypsum-salt rocks had high TOC. For example, TOC of the lamellar gypsum salts distributed in the Suez Rift Valley was up to 30%, but such the lamellar gypsum-salt rocks had no universal reference to hydrocarbon-generation potential (Javor, 1983; Richardson et al., 1988; Grice et al., 1998; Ma et al., 2002; Kluska et al., 2013). It needed to be emphasized that values of TOC was the residual organic carbon content, and was not fully related to original organic matter, especially for high-mature source rock. Generally, the marine gypsum-salt rock series underwent multi-stage hydrocarbon generation and hydrocarbon accumulation, the original organic matter might have been partially converted into hydrocarbons, so evaluation of hydrocarbon-generation potential could not depend on the residual organic carbon content only. Even for source rocks with same TOC, the hydrocarbon-generation potential might differ greatly due to various compositions of hydrocarbon-generation materials (Qin et al., 2010). In summary, it was controversial that the gypsum-salt rock series had no hydrocarbon-generation potential because of its low organic matter abundance. The continental gypsum-salt rock series was used to be regarded as poor source rocks (Huang et al., 1993) because their TOC values were mostly lower than the widely-accepted lower limit of TOC of source rock (Huang et al., 1984). However, later exploration and geological practices in Jianghan and Qaidam basins showed that the continental gypsum-salt rock series was capable to be the high-quality source rocks, and not all gypsum-salt rock series had very low TO; in the deepwater saline lake where the gypsum-salt deposited, source rocks with high abundance of organic matter and good type of kerogen might be developed. The reason why the marine gypsum-salt rock series had low TOC probably was that researches on generation, distribution, preservation mechanism and evolution of organic matter were insufficient. Low TOC of the gypsum-salt rock series might be attributed to followings: (a) The primary sedimentary environment of the gypsum-salt rock series was not favorable for superposition of high biomass yield in surface water and anaerobic environment in bottom water. High-quality source rocks of the gypsum-salt rock series mainly were developed in the superposed areas of high biomass yield and anaerobic environment, so its distribution was restricted. In some areas, biomass yield of species was low due to influence of salinity, temperature and pH of surface seawater, and thus the TOC of the gypsum-salt rock series was low. In some other areas, though the surface seawater had very high biomass yield, the stratified brine was not formed, or the stratified brine was damaged because of climate change, reduction of saline source materials and other factors, that was not in favor of organic matter preservation and resulted in low TOC of source rocks. (b) Organic matter in the gypsum-salt rock series had been expelled through hydrocarbon generation. Current researches on

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hydrocarbon generation simulation of marine gypsum-salt rock were insufficient, whether hydrocarbons had been expelled during the evolution of the gypsum-salt rock series could not be determined. Because carbonate rocks was an important part of the marine gypsum-salt rock series, and the marine gypsum-salt rocks were closely related to the marine carbonate rocks in their genesis and spatial distribution, therefore, an analogy of the marine carbonate rock was used to discuss hydrocarbon generation process of the gypsum-salt rock series. It was worthy that hydrocarbon sources of some high-quality carbonate rocks had the TOC of 8e12% during the moderate mature stage and the low mature stage, but in the high mature stage, its TOC rapidly decreased to 1e4%, indicating that TOC of source rocks with good type of kerogen was significantly reduced during the sour rock evolution. According to a systematic analysis on variation of TOC during the organic matter evolution, TOC of good source rocks could be reduced by up to 80% in the high mature stage, while TOC of poor source rocks was reduced by 20% at most (Jarvie, 2012, 2014). This had an important significance to evaluate the gypsum-salt source rocks of high mature stage and low organic abundance in China. In the high mature stage, for the gypsum-salt rock series with low TOC, a possibility that this kind of rocks with high TOC in the geological history could not be excluded, and perhaps organic matter had been expelled through hydrocarbon generation in the geological history. In addition, the mechanical dissolution would occurred in the thick-bedded salt rocks, thus internal hydrocarbons of the thick-bedded salt rocks would be differentiated and expelled, and become important hydrocarbon source for large oil fields (Szatmari, 1980). (c) Acid-soluble organic matter was ignored in the traditional measurement method of TOC, thus causing the measured values to be low. According to a standard procedure for determining organic carbon content established by Standardization Committee of Petroleum Geology Exploration in China (SCPGE, 1996), the crushed sample was added with hydrochloric acid and was heated to remove inorganic carbon, then the residue was repeatedly rinsed with distilled water untill the filtrate was neutral, thereafter the solid residue was used to measure TOC using a carbon and sulfur analyzer, and the residual liquid was discarded. Although this method eliminated influence of inorganic carbon, the acid-soluble organic matter in the acid solution was discarded, and was not measured by the analyzer, resulting in the lower measured values of TOC. The loss of the acid-soluble organic matter might cause great deviation in measured values of TOC of such low organic abundance source rock of the gypsum-salt rock series. (d) The contribution of different bio-precursors (plankton, benthos and terrigenous higher plants) to TOC was different. The bio-precursor of the marine gypsum-salt rock series primarily was plankton (such as algae), which had a low contribution to TOC. (e) In the evaporation environment from neritic anaerobic boundary to photic zone, the organic matter was likely to be decomposed by bacteria and sulfate reduction into H2S, CO2 and H2O (Adam et al., 1998): Organic matter þ SO2 4 /H2S þ CO2 þ H2O

(1)

As a result of this reaction, the organic matter was partially consumed, and hence the measured values of TOC were low. 5.2.3.2. Hydrocarbon-generation materials of the gypsum-salt rock series. In the hydrocarbon-generation materials of the gypsum-salt rock series, besides primary hydrocarbon-generation biological assemblages, the underestimated acid-soluble organic matter also had important contribution to hydrocarbon generation. The Gypsum-salt rock series had high-quality hydrocarbon-

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generation biological assemblages, and hydrocarbon source materials dominated by plankton and bacteria were equivalent to Type-I kerogen with very high hydrocarbon conversion rate, that might be the largest contributor to oil and gas (Liu et al., 2010, 2012). Furthermore, the redox environment not only controlled organic matter abundance but also influence on type of organic matter of the gypsum-salt rock series. Most of source rocks of the gypsumsalt rock series had good types of organic matter, which was dominated by Type-I and Type-II1; that was because that aerobes would selectively decompose the deposited organic matter in the aerobic environment, the aquatic-derived organic matter was readily decomposed due to rich lipids, but the terrigenous organic matter abundant in aromatic structures and phenol derivatives was toxic to many microorganisms, and was not easy to be decomposed (Jin and Zha, 2000). After decomposition by aerobes, the organic matter formed in the oxidative environment was then dominated by aromatic structures, so its type of organic matter was poor; the organic matter of the gypsum-salt rock series was mostly in the anoxic environment without decomposition by aerobes, so its type of organic matter was good. Due to good type of organic matter, the gypsum-salt rock series probably had expelled hydrocarbons during the geological evolution process (Jarvie, 2012, 2014), and relative high hydrocarbon conversion rate made the source rock in the high mature stage had lower values of TOC. Therefore, to accurately evaluate hydrocarbon-generation potential of the gypsum-salt rock, besides TOC, it was necessary to study hydrocarbongeneration organisms and analyze hydrocarbon conversion rates of different bio-precursors of source rocks. Studies of hydrocarbongeneration organisms mainly focused on hydrocarbon-generation simulation of modern organisms and biological fossils, which could be used to make accurate evaluation on hydrocarbongeneration potentials of various organisms (Qin et al., 2010, 2014; Hu et al., 2014). However, the hydrocarbon generation experimental simulation of the gypsum-salt rock series source rocks was insufficient and some data was less in the world, so some related researches would be required urgently. The organic acid salt extensively developed in the gypsum-salt rock series was one kind of special chemical compounds which were capable of hydrocarbons generation, leading to more diversified hydrocarbon generation processes of such high-mature and low-abundance source rock of gypsum-salt rock series. The organic acid salts referred to compounds formed by interaction of organic acids in organic sediments with Ca2þ, Mg2þ and other metallic ions (Sun et al., 2013), it consisted of primary and secondary organic acid salts. Among them, the primary organic acid salts were formed in the process of organic matter conversion into kerogen, while the secondary organic acid salts were formed in situ or in the migration process during hydrocarbon generation process of kerogen (Liu

Fig. 6. Relationship between organic acid salts and TOC of source rocks (Liu et al., 2013a,b) showing organic acid salts was an important supplement for TOC of source rocks.

et al., 2012). The organic acid salts in source rocks had very high hydrocarbon conversion rate, and were the important hydrocarbon-generation source materials. Especially, for highmature and low-abundance marine gypsum-salt rock series, the organic acid salts could be as a kind of important regenerated hydrocarbon sources (Lei et al., 2010; Liu et al., 2012, 2013a) (Fig. 6). In addition, the organic acids could be converted into organic acid salts in the hypersaline water (Kawamura and Nissenbaum, 1992), the gypsum-salt rock series had very high brine saturation and thus was rich in organic acid salts, so the organic acid salts had an important influence on hydrocarbon-generation potential of the gypsum-salt rock series. 5.3. Correlation of hydrocarbon and source Organic geochemical correlation between hydrocarbon and organic matter of source rocks was an important content for hydrocarbon source condition research and resource potential evaluation. Previous studies of carbon, hydrogen and sulfur isotopes as well as biomarker compounds demonstrated that the gypsum-salt rock series could act as hydrocarbon sources. (1) Hydrogen isotopic composition of natural gas primarily depended on salinity of depositional water, followed by maturity influence. Under similar conditions of maturity, isotopes of gas from the hypersaline medium source rocks were heavier than that from the hyposaline medium source rocks, so the sedimentary environment of source rock could be determined (Liu et al., 2007). For Leikoupo Formation in western Sichuan, Ordovician pre-salt hydrocarbon reservoirs in the eastern Ordos Basin and Tazhong area in the Tarim Basin, hydrogen isotopes of gas were heavy, indicating that source rocks were deposited in the hypersaline water environment, probably were the marine gypsum-salt rock series. (2) Previous studies showed that the biomarker compound indicators including trifluorene series compounds (fluorene, dibenzofuran and dibenzothiophene), pristane-to-phytane ratio (Pr/Ph) and gammacerane could reflect sedimentary environment of source rock, and identified different sedimentary environment (such as marine facies, saline lake facies, brackish wateresaltwater facies and limnetic facies (Wang, 1995; Li et al., 2001; Li and He, 2008). Characteristics of biomarker compounds from Silurian bituminous sandstone in Tarim Basin showed that ratios of Pr/Ph were low (0.32e0.76) with high predominance of phytane, indicating the hypersaline reduction environment; trifluorene series compounds also showed that the depositional environment of source rocks was the reduction environment (Hu et al., 2015), the above evidences all suggested that hydrocarbon source of the bituminous sandstone may be related to gypsum-salt rock series. (3) Sulfur, as a marker compound, could also provide information about evolution of source rock. Hydrocarbon in the gypsum-salt rock series was usually characterized by high sulfur content, which should be related to TSR and BSR (Cai et al., 2003; Zhu et al., 2006; Liu et al., 2013b). Gas reservoirs with high content of sulfur in Triassic Feixianguan Formation, Jialingjiang Formation and Leikoupo Formation of Sichuan Basin were all sandwiched between the gypsum-salt rock serieses, indicating the gas was closely related to the gypsum-salt rock series. 6. Conclusions There was a consensus that the gypsum-salt rock series could be

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regarded as good caprocks, further explorations and researches eventually showed that some gypsum-salt rock series could also as good reservoirs or even high-quality source rocks. Marine gypsumsalt rock series was characterized by high thermal maturity and low organic matter abundance, but their hydrocarbon-generation potential and hydrocarbon-generation mechanism were controversial. Breakthroughs in hydrocabron exploration of marine gypsumsalt rock series and numerous geological evidences indicated that the marine gypsum-salt rock series had good hydrocarbongeneration potential, and some research findings could be concluded as below. (1) With regard to low TOC of the gypsum-salt rock series at present, high-quality hydrocarbon-generation materials in their primary strata had undergone hydrocarbon generation and conversion in the geological history and thus provided hydrocarbon sources for paleo-reservoirs, resulting in low residual TOC currently. (2) In terms of the evaluation method for the gypsum-salt rock series, the conventional measurement method of TOC ignored organic acid salt could be as the important regenerative hydrocarbon source and underestimated the hydrocarbon generation of the gypsum-salt rock series. (3) According to analysis of hydrocarbon source development process of gypsum-salt rock series, biological assemblage, hydrocarbon-generation materials and correlation of hydrocarbon and source, the gypsum-salt rock series had good hydrocarbon-generation potential. Due to variations in origin, geological setting and stratigraphic sequence distribution, the marine gypsum-salt rock series could play one or more important roles in the source formation, hydrocarbon generation, reservoir formation, hydrocarbon accumulation and preservation processes. Acknowledgement The work was supported by the National Key Basic Research Program of China (973 Program) (No. 2012CB214801) and the National Natural Science Foundation of China (No. U1663201). References Adam, P., Philippe, E., Albrecht, P., 1998. Photochemical sulfurization of sedimentary organic matter: a widespread process occurring at early diagenesis in natural environments? Geochimica Cosmochimica Acta 62 (2), 265e271. Bao, H.P., Yang, C.Y., Huang, J.S., 2004. Evaporation drying” and “reinfluxing and redissolving”-a new hypothesis concerning formation of the Ordovician evaporites in eastern Ordos Basin. J. Palaeogeogr. 6 (3), 279e288 (in Chinese). Barbe, A., Grimalt, J.O., Pueyo, J.J., Albaiges, J., 1990. Characterization of model evaporitic environments through the study of lipid components. Org. Geochem. 16 (4), 815e828. Busson, G., 1992. Relationship between different types of evaporitic deposits, and the occurrence of organic-rich layers (potential source-rocks). Carbonates Evaporites 6, 177e192. Cai, C., Worden, R.H., Bottrell, S.H., Wang, L., Yang, C., 2003. Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China. Chem. Geol. 202 (1/2), 39e57. Cao, J., 2014. Preliminary Study on Destruction of Gypsum Cap Rock. Sinopec Petroleum Exploration & Production Research Institute, Wuxi (in Chinese). Chen, J.P., Liang, D.G., Zhang, S.C., Bian, L.Z., Zhong, N.N., Zhao, Z., Gong, F.H., Deng, C.P., Zhang, D.J., Zhang, B.M., Liang, Y.B., Tu, J.Q., 2013. Shale and mudstone: essential source rocks in Proterozonic to Paleozonic marine basins in China. Acta Geol. Sin. 87 (7), 905e921 (in Chinese). Copeland, B.J., Jones, R.S., 1965. Community metabolism in some hypersaline waters. Tex. J. Sci. 17 (2), 188e205. Curial, A., Moretto, R., Dumas, D., Dumas, D., Sarl, G., 1990. Organic Matter and Evaporates in the Paleogene West European Rift: the Bresse and Valence Salt Basin (France). AAPG, Tulsa. Dai, J.X., 2003. Pool-forming periods and gas sources of Weiyuan. Petrol. Geol. Exp. 25 (5), 473e480 (in Chinese). Degens, E.T., Stoffers, P., 1976. Stratified waters as a key to the past. Nature 263,

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