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Abstract

The hydrocarbon phase state of deep to ultra-deep reservoirs in the Tarim and Sichuan basins has been of great interest in oil and gas exploration. Based on a combination of molecular dynamics simulation, gold-tube pyrolysis experiments, and geological-geochemical theory, this study discusses the mechanisms governing the stability of oils in deep reservoirs from the perspectives of their reservoir accumulation histories and chemical reactions. Generally, the reason for the existence of liquid oil in the Tarim Basin is widely considered to be only controlled by external geological conditions, mainly including low geothermal gradient, absence of thermal events, low maximum reservoir temperatures, and late hydrocarbon generation process. However, this study firstly proposed that the chemical composition of oil is an internal factor for its thermal stability. The simulation results reveal that the polycondensation reactions of asphaltene will release hydrogen atoms, which can provide a necessary hydrogen source for cracking of liquid chain hydrocarbons. It means that the presence of asphaltene components can promote the cracking of chain hydrocarbons and generate methane. The normal mature oil in the Sichuan Basin generally has higher contents of asphaltenes than that of the high-mature light oil of the Tarim Basin, so more hydrogen has historically been available for the cracking of oil to gas. By looking at the accumulation histories and chemical compositions of the crude oils, this study first explains the stable long-term storage of liquid hydrocarbons in the Tarim Basin, providing important guidance for future deep to ultra-deep oil and gas exploration.

Keywords

Deep oil reservoir molecular simulation hydrocarbon phase state chemical composition oil accumulation history gold-tube pyrolysis

Introduction

Deep to ultra-deep marine sequences are important targets for future exploration, and may provide a vital option for strategic energy replacement in China (Jin and Cai, 2006; Zhu et al., 2010; He et al., 2016; Li et al., 2021). There are three major cratons in China: the North China Craton, the Tarim Craton, and the Yangtze Craton. The North China Craton deposits a set of extremely thick Meso-Neoproterozoic strata (Wang and Gong, 2018), while the Tarim and Yangtze cratons both have widely developed deep to ultra-deep Sinian-Lower Paleozoic sequences (Zhao et al., 2012; Zou et al., 2014a). Oil seepage or solid bitumen occurs widely in the Proterozoic reservoirs of the Yanliao Faulted-Depression Zone in the North China Craton, but no commercial petroleum accumulation has yet been found (Gao et al., 1991; Wang et al., 2016; Xiao et al., 2022). The Tarim Basin and the Sichuan Basin are both very important petroliferous basins in China and are both rich in deep to ultra-deep oil and/or gas resources (Zhao et al., 2012; Zou et al., 2014a; Wei et al., 2015). However, there are significant differences between the hydrocarbon phases of the deep to ultra-deep resources in the two cratons (Zhang et al., 2007). Large quantities of liquid oils are found in the Tarim Basin (heavy, normal, light, and condensate oils) (Zhu et al., 2010; Zhu et al., 2012; Ma et al., 2015; Zhu et al., 2016; Zhu et al., 2019), while the Sichuan Basin contains mainly dry gas (Zou et al., 2014a; Zou et al., 2014b; Wei et al., 2015; Yang et al., 2020a, 2022).

Zhang et al. (2007) pointed out that the maturity of the source rocks in the Sichuan Basin plays a key role in the oil and gas phases (Zhang et al., 2007). The Paleozoic Dengying Formation source rock has already entered high- to over-mature stages, and with vitrinite reflectance values exceeding 2.0% (Zou et al., 2014a). Zhu et al. (2010) reported that the marine carbonate reservoirs in the Sichuan Basin experienced the high paleo heat flow, high temperatures, and oil cracking process during the Late Mesozoic (Zhu et al., 2010; Liu et al., 2018; Xu et al., 2018). Thermochemical sulfate reduction (TSR) is considered to have been a catalyst for the formation of oil-cracking gas (Zhu et al., 2005; Zhang et al., 2008; Zhu et al., 2019). Generally, the liquid hydrocarbon phase of the ultra-deep marine reservoirs in the Tarim Basin is widely accepted as a result of the compensating effect of long-term low geothermal gradients and rapid deep burial processes (Zhu et al., 2010; He et al., 2016; Liu et al., 2016). Ma et al. (2015) carried out thermal simulations experiments using heavy, normal, and waxy oils from the Tahe oilfield in a confined gold-tube system, which revealed that the oils still stable in a separate phase state at temperatures of 178‒205 °C (Ma et al., 2015). Analysis of the thermal stability of various components of the crude oils indicated that cracking of the Tarim oil begins at about 9000‒10,000 m, where the reservoir temperature is higher than 210 °C (Zhu et al., 2012).

The discovery of ultra-deep oil in the Tahe oilfield contradicted Tissot’s theory of a ‘death line’ of liquid hydrocarbons (Tissot, 1978; He et al., 2016), and revealed that high temperature is not the only factor controlling oil cracking or affecting the preservation of liquid hydrocarbons. In the study, the authors further point out that the chemical composition of crude oils is also a major factor affecting hydrocarbon phase states. Based on a detailed analysis of the hydrocarbon accumulation histories of the Tarim and Sichuan basins, combined with gold-tube pyrolysis experiments and molecular simulation of the mixed components of saturated hydrocarbons and asphaltenes, this study clarifies the principal controlling factors for the stable existence of liquid hydrocarbons in the Tarim Basin at depths of more than 7000 m. This result is of great significance for the future exploration of deep to ultra-deep oil and gas fields.

Geological settings

The Tarim and the Sichuan basins, located in the Tarim Carton and the Yangtze Carton, respectively, are major petroliferous basins in China (Figure 1(a)). A series of large oil and gas fields have been discovered in Paleozoic and Precambrian carbonate reservoirs in both basins. The Sichuan Basin hosts two great Sinian–Cambrian marine carbonate gas fields: the Weiyuan and the Anyue gas fields (Figure 1(c)). In 2013, natural gas reserves in the Lonwangmiao Formation in Anyue gas field were proved to be 4.4 × 10¹¹ m³ (Zou et al., 2014b). In the Tarim Basin, the proportion of petroleum resources is greater, with estimated reserves including ∼1.2 × 10¹⁰ tons of oil and 1.48 × 10¹³ m³ of gas were estimated (Zhu et al., 2016).

Figure 1.

The locations of the three major cartons in China (a) and the distribution of tectonic units and oil-gas fields in the Tarim Basin (b) and Sichuan Basin (c).

The Sichuan Basin covers an area of 1.8 × 10⁵ km² and is divided into six structural zones: the Western Sichuan Structural Zone, the Central Sichuan Structural Zone, the Southeastern Sichuan Structural Zone, the Southern Sichuan Structural Zone, the Southwestern Sichuan Structural Zone, and the Northern Sichuan Structural Zone (Figure 1(c)) (Shi et al., 2017). A succession of unmetamorphosed marine sediments—from Sinian to the lower Triassic—overlie on the volcanic basement (Zou et al., 2014a). The Sinian sequence is composed of the Lower Doushantuo Formation (Z₁ds) and the Upper Dengying Formation (Z₂dn). The former is mainly composed of mudstone, shale, sandstone, and dolomite, while the latter features a succession of dolomite sediments intercalated with clastic rocks. The second (Z₂dn²) and fourth members (Z₂dn⁴) of the Dengying Formation are the Sinian reservoirs of the Anyue gas field (Zou et al., 2014b; Zhu et al., 2015; Liu et al., 2019). The Lower Cambrian sequence, containing the Qiongzhusi, Canglangpu, and Longwangmiao formations, was deposited in an open- to restricted-marine environment. The Qiongzhusi Formation (Є₁q) consists of black shale, mudstone, and argillaceous dolomite deposited during a transgressive phase and considered to be the main potential source rocks (Zou et al., 2014b; Zhu et al., 2015; Gao et al., 2016; Wang et al., 2019).

The Tarim Basin is a large superimposed basin, with an area of 5.6 × 10⁵ km². It has experienced multi-cycle tectonic movements (Zhu et al., 2019) that eventually formed the present structural pattern, which contains five depressions and three uplifts (Figure 1(b)). All the marine oil and gas resources so far discovered in the Tarim Basin are distributed around the paleo-uplifts. A number of giant oil and gas fields, including Halahatang oil field, Tahe oil field, and Tazhong oil field, have been discovered in the Ordovician in the Tabei and Tazhong uplifts (Fang et al., 2016; Xiao et al., 2016; Zhu et al., 2016; Zhu et al., 2019; He et al., 2022). Two sets of potential marine source rocks—the Cambrian-Lower Ordovician and Middle-Upper Ordovician—have been identified and analyzed over several decades. However, it is still uncertain which set is the main source rocks (Zhang et al., 2002; Zhang and Huang, 2005; Li et al., 2015; Huang et al., 2016). A succession of unmetamorphosed marine sediments ranging from Sinian to Devonian overlie on the Pre-Sinian cratonic crystalline basement in the Tarim Basin (Zhu et al., 2019). The Lower-Middle Ordovician Yingshan Formation and the Middle Ordovician Yijianfang Formation, composed of calcarenites and dolomite, provide the main reservoirs of the Halahatang and Tahe oilfield (Xiao et al., 2016).

Geological evidences

Present burial depths and temperatures of reservoirs

Present burial depth of reservoirs

The main reservoirs in the Sichuan Basin are the Cambrian Longwangmiao Formation and the Sinian Dengying Formation (Wei et al., 2015; Yang et al., 2020a). Based on stratigraphic data from more than 20 wells, the present maximum depth of the bottom boundary of the two reservoirs has been determined in the Chuanzhong Uplift, Sichuan Basin (Figure 2). Figure 2 shows that the current burial depth of the two sets of reservoirs is deeper in the northeast, and gradually becoming shallower toward the southwest. The present burial depth of the Cambrian Longwangmiao Formation is mainly in the range of 4500‒4800 m (Figure 2(a)), while the present maximum burial depth of the Sinian Dengying Formation reservoir is less than 5500 m, generally 5300‒5500 m (Figure 2(b)). Clearly, the present burial depth of the reservoirs in the Sichuan Basin is insufficient to cause complete cracking of crude oil to into dry gas.

Figure 2.

Contour map of burial depths at the bottom boundaries of the gas reservoirs in the Longwangmiao (a) and Dengying formations (b), Sichuan Basin.

The major reservoirs in the Tarim Basin are in the Cambrian–Ordovician dolomite (Zhao et al., 2012; Zhu et al., 2019). Few wells have been drilled through the Cambrian anywhere in the basin so, for this study, the current burial depth of the bottom boundary of the Ordovician reservoirs in the Tabei area of the Tarim Basin was determined on the basis of stratigraphic data from 94 wells. Figure 3 shows that the present burial depth of the Ordovician dolomite reservoir in the Tabei area gradually decreases from west to east. It generally exceeds 5500 m and reaches more than 7000 m in the west of the Tabei area (Figure 3). Recently, light crude oil has been obtained from the Cambrian reservoir at more than 8200 m in Luntan-1 well (Yang et al., 2020b, 2020c).

Figure 3.

Contour map of burial depths at the bottom boundaries of the Ordovician oil reservoirs in the Tabei area, Tarim Basin.

Present temperature of reservoirs

Using bore-holes of temperature data, the present burial depth of reservoirs, and the geothermal gradients, this study describes the current temperatures and geothermal system of the Cambrian Longwangmiao and Sinian Dengying formations in the Sichuan Basin (Figure 4), and the carbonate reservoirs at 6000 m and 7000 m in the Tabei area (Figure 5). The distribution of isotherms shows that the present reservoir temperature of the Sinian Dengying Formation in the Chuanzhong Uplift is about 10 °C higher than that of the Cambrian Longwangmiao Formation, although both are generally less than 150 °C (Figure 4). The Cambrian–Ordovician reservoirs in the Tabei area are much deeper than the Sinian–Cambrian reservoirs in the Chuanzhong Uplift (Figures 2 and 3) and also have reservoir temperatures 30‒40 °C higher than those of the Sichuan Basin reservoirs (Figures 4 and 5). Although the geothermal gradient in the Tabei area is relatively low (∼20 °C/km), the maximum temperatures of the reservoirs at 6000 m and 7000 m in the northern part of the Yakela Fault-Uplift exceed 160 °C and 190 °C, respectively (Figure 5).

Figure 4.

Isotherms of the Longwangmiao (a) and Dengying formations (b), Sichuan Basin.

Figure 5.

Isotherms at 6000 m (a) and 7000 m (b) reservoirs in the Tabei area, Tarim Basin.

Both the present depths and the temperatures of the Cambrian–Ordovician reservoirs in the Tarim Basin are much greater than those of the Sinian–Cambrian reservoirs in the Sichuan Basin, which appears counter-intuitive given the fact that a large amounts of commercial liquid oil and gas have been discovered in the Tarim Basin, while the Sichuan Basin apparently only contains dry gas (Jin and Cai, 2006; Zhang et al., 2007; Zhao et al., 2007). The present burial depth (<5500 m) and temperature (<150 °C) of the reservoirs in the Sichuan Basin are clearly insufficient to cause complete cracking crude oil into dry gas, which indicates that present burial depths and temperatures of reservoirs are not the main factors controlling the differences between the hydrocarbon phases in the deep to ultra-deep reservoirs of the Sichuan and the Tarim basins.

Burial and thermal evolution histories

The paleo temperature evolutions of the formations can be determined from the reconstructions of their burial and thermal histories. The erosion timings and missing sediment thicknesses of the Tarim and Sichuan basins were obtained from the generally accepted conclusions of previous studies (Zhang et al., 2000; Zhao et al., 2005; Li et al., 2007; Yang et al., 2018a, 2018b). Ni et al. (2016) and Xiao et al. (2016) reconstructed the paleo-heat flow history of the Tabei Uplift and the burial history of the RP7 well in the uplift (Figure 6(a)). The heat flow was found to have been 53 mW/m² during the Early Ordovician, gradually decreasing to 47 mW/m² during the Late Carboniferous. A thermal ‘kick’ then occurred during the Permian, and then from the Late Permian to the present day, the heat flow gradually decreases to 36 mW/m² (Figure 6(a)) (Ni et al., 2016). These figures confirm that the lower Paleozoic strata of the Tarim Basin are currently at their maximum depth and highest temperature (∼170 °C) (Figure 6(a)), which essentially means that the temperature of the reservoirs has never been high enough to cause extensive oil cracking.

Figure 6.

Burial and thermal evolution histories of RP7 well in the Tarim Basin (a) and GS6 well in the Sichuan Basin (b), showing the hydrocarbon generation stage of source rocks, and episodes and timing of oil accumulations.

Yang et al. (2018a, 2018b) constructed the burial and thermal histories of the GS6 well in the Sichuan Basin using PetroMod 1D modeling software (Figure 6(b)) (Yang et al., 2018a, 2018b). The heat flow was found to be lower than 56 mW/m² until the Late Devonian, with an abrupt rise to ∼80 mW/m² occurred in the Late Permian. The heat flow gradually decreased after the Triassic, and the present day heat flow is calculated to be as low as approximately 58 mW/m² (Zhu et al., 2015; Yang et al., 2018b). The burial temperature of the Sinian–Cambrian sequence in the Basin reached its maximum value (∼220 °C) in the Early Cretaceous, with a corresponding maximum burial depth of 8500‒9000 m (Figure 6(b)). This allowed the cracking of crude oil into gas in the paleo-oil reservoirs in the Chuanzhong Uplift.

The Sinian-Lower Paleozoic deep to ultra-deep sequences in the Tarim and Sichuan basins have very different burial and thermal evolution histories (Figure 6). Although the present burial depth and temperature of the Sichuan Basin are less than those of the Tarim Basin, the Sichuan Basin experienced rapid deep burial and abnormally high paleo-temperatures during the Triassic to Cretaceous (Figure 6(b)), which is thought to be an important reason for the extensive occurrence of gas reservoirs. This scenario also tends to confirm that the stability of liquid oil reservoirs depends on the maximum paleo-temperature of the reservoirs rather than the present temperature.

Episodes and timing of oil reservoirs

Hydrocarbon inclusions, as small petroleum reservoirs, have experienced the entire history and evolution of oil migration and accumulation (Burruss et al., 1985; Volk and George, 2019; You et al., 2020). This study therefore unravels the hydrocarbon accumulation histories of the two basins through the investigation of reservoir inclusions.

Observations and microthermometry of fluid inclusions

Observation under plane polarized light (PPL) and ultraviolet light (UV) identifies two types of oil inclusions in the Ordovician dolomites of the Tarim Basin, trapped in the microfractures (Figure 7(a)–(h)). Type I oil inclusions are characterized by a yellow color under UV (Figure 7(b)) and a brown color under PPL (Figure 7(a)). Type II oil inclusions are more abundant and appear blue-white under UV (Figure 7(d), (f), and (h)) and colorless under PPL (Figure 7(c), (e), and (g)). Based on the intersection of two isochores of oil inclusions and their coeval aqueous inclusions within the P–T coordinate system, the trapping temperatures of the two types of fluid inclusion are concentrated in the ranges of 90–100 °C and 140–160 °C, respectively (Figure 7(i)–(l)) (Ni et al., 2016; Xiao et al., 2016; Song et al., 2017). The petrography of fluid inclusions, the fluorescence of oil inclusions, and bimodal Th distribution histograms all suggest that the Ordovician reservoirs of the Tarim Basin probably experienced two episodes of oil charging. Moreover, the scale of hydrocarbon generation at trapping temperature of 140–160 °C seems to be larger than that at 90–100 °C, indicating high-mature hydrocarbons.

Figure 7.

Series of photomicrographs showing the distribution of oil inclusions under plane polarized light (PPL; a, c, e, g) and ultraviolet light (UV; b, d, f, h), and homogenization temperature histograms (i–l). (a and b) Trails of two-phase oil inclusions in healed fractures, JY-4 well-1; (c and d) trails of two-phase oil inclusions in healed fractures, RP-7 well-1; (e and f) two-phase oil inclusions, JY-4 well; (g and h) trails of two-phase oil inclusions in healed fractures, RP-7 well-1; (i) homogenization temperature histogram (HTH) of RP-7 well (modified from Xiao et al., 2016); (j) HTH of YQX-1 well (modified from Song et al., 2017); (k) HTH of T-904 well; (l) HTH of JY-4 well.

Hydrocarbon generation and accumulation in the Tarim Basin

Rapid subsidence of the sequences first occurred in the Silurian, with the temperature of the Cambrian–Ordovician source rocks being over 80 °C and their burial depths reaching approximately 2500 m in the late Silurian, pushing the source rocks into the first stage of hydrocarbon generation (Figure 6). However, the rapid uplift in the early Devonian abruptly interrupted the oil generation and expulsions, resulting in a short period of limited hydrocarbon generation (Figure 6(a)) (Zhu et al., 2010). The first hydrocarbon generation and charging stage corresponds to the trapping temperatures of 90–100 °C for the fluid inclusions in the Ordovician reservoirs. During the Neogene, a second episode of rapid subsidence occurred, with the burial depth of the Cambrian–Ordovician formations increasing to approximately 7000 m and the temperature reaching 170 °C (Figure 6(a)). This corresponds to the second stage of hydrocarbon generation in the study area, which produced large amounts of light and condensate oils (Figure 6(a)). However, a low thermal gradient and insufficient time–temperature compensation during the periods of rapid burial meant that little thermal cracking occurred in the crude oils (Zhu et al., 2019).

The burial history, geothermal evolution, hydrocarbon generation history, and microscopic observation and the trapping temperatures of fluid inclusion indicate that the first episode of oil accumulation occurred from the Late Silurian to the Early Devonian (419–410 Ma) and the second during the Neogene (16–8 Ma) (Figure 6(a)) (Ni et al., 2016; Xiao et al., 2016). Both of these accumulation episodes occurred during rapid subsidence stages that correspond to the main oil generation stages. However, the first episode was interrupted by a sudden uplift in the early Devonian (Figure 6(a)). The source rocks therefore generated only relatively small amounts of hydrocarbons during the first episode, which probably explains the limited numbers of yellow-fluorescing oil inclusions in the Ordovician reservoirs (Figure 7(a) and (b)). The more plentiful oil inclusions with blue-white fluorescence were mostly trapped in the second oil charging stage (Figure 7(c)–(h)).

Hydrocarbon generation and accumulation in the Sichuan Basin

The burial history of GS6 well in the Sichuan Basin shows that the Cambrian Qiongzhusi Formation as main source rock first entered the oil generation stage during the Devonian period, with the temperature at 80 °C. The oil generation process was interrupted then by the Carboniferous uplift (Figure 6(b)). Rapid subsidence occurred again in the Permian, and the oil generation process was restarted at about 275 Ma (Figure 6(b)). Based on the geological analogy method, Yang et al. (2020a) also proposed that the paleo-oil reservoirs in the Dengying Formation accumulated at around 275–263 Ma (Yang et al., 2020a). After the Triassic, the reservoir temperature rose rapidly, reaching over 200 °C, which is considered to have caused the liquid oils to crack into gas at 175–144 Ma (with temperatures of 180–200 °C) (Figure 6(b)). Some studies, however, have suggested that the oil cracking might have been directly caused by the hydrothermal events (Jiang et al., 2016; Yang et al., 2018a, 2018b), such as the Emeishan mantle plume that occurred at 252 Ma (He et al., 2003). In any case, all of the reservoirs are now full of gas. In addition, microscopy and laser Raman spectroscopy have revealed widespread pure methane, methane-bearing, and solid bitumen-bearing inclusions in the Sinian dolomite reservoirs (Yang et al., 2018b). Although formation uplift since the late Cretaceous has reduced the current reservoir temperature to 150–140 °C (Figure 6(b)), the oil cracking has proved irreversible (Zou et al., 2014a; Zhu et al., 2015).

Molecular simulation and gold-tube pyrolysis experiment

Chemical compositions of crude oils changing with the thermal evolution

For this study, forty-nine crude oil samples were collected from five basins, including seventeen samples from the Tarim Basin, fourteen from the Fushan Depression, five from the Termit Basin, seven from the Muglad Basin and six from the Liaohe Basin. These were used to analyze the relationships between fractions of crude oils (saturate, aromatic, and non-hydrocarbon) and thermal maturity. The percentage of resins and asphaltenes usually range from 0% to 40% in non-degraded crude oils, and they have high proportions of immature oils, but decreases with increasing depth and subsequent cracking (Tissot and Welte, 1980). However, microbial activity, water washing, and oxidation always alter the gross composition of crude oils due to elimination or degradation of hydrocarbons. The oil samples selected for the study therefore are all normal oils with no evident biodegradation or other secondary effects.

Radke and Welte (1983) proposed the methylphenanthrene index (MPI) based on the relative abundances of four isomers of methylphenanthrene (Radke et al., 1982; Radke and Welte, 1983). The formula for conversion between the MPI and vitrinite reflectance is derived from measured vitrinite reflectance (Rc = 0.4 + 0.6*MPI₁) (Radke and Welte, 1983) and has been widely used in maturity evaluation of source rocks and related crude oils. The crude oils from the Fushan Depression, the Muglad Basin, and the Liaohe Basin come from lacustrine mudstone source rocks, the maturity of which were calculated using this formula. The crude oils from the Tarim Basin are light, high maturity oils derived from marine carbonate source rocks. In this case, the formula for calculating Rc (%) is 1.20 + 0.09*MPI₁ (Yang et al., 2018d). The crude oils from the Termit Basin were generated from marine shale source rocks, in which case the formula for calculating Rc (%) is 0.20 + 0.88MPI₁ (Tang and Li, 2015).

Statistical results show that the relative content of saturated hydrocarbons in crude oils increases with thermal evolution, while the relative content of non-hydrocarbons and asphaltenes decreases (Figure 8). As Rc (%) increases (from 0.3% to 1.5%), the saturated hydrocarbon contents of the crude oils increase significantly from approximate 50% to more than 90%, while the aromatic hydrocarbon contents also increase slightly, by less than 30%. Non-hydrocarbon content in high-mature oils gradually decreases to less than 5% (Figure 8). In this study, the deep to ultra-deep light oils and condensate oils in the Tarim Basin are high-mature oils generated in the Neogene, while the oils of the paleo-reservoirs in the Sichuan Basin are mature oils produced within main oil generation window (Figure 8). The relative contents of asphaltenes and non-hydrocarbons in oils from the Sichuan Basin paleo-reservoirs are accordingly significantly higher than those in the Tarim Basin oils (Figure 8).

Figure 8.

Changes in the proportions of saturate (red), aromatic (blue) and non-hydrocarbon (green) fractions relative to the Rc (%) over time. Note: non-hydrocarbon = resins + asphaltenes.

Construction and molecular simulation of the mixed structure model of saturated hydrocarbons and asphaltenes

Hydrocarbon cracking and polycondensation reactions

With increasing temperatures, cracking and polycondensation reactions occur simultaneously in crude oils, with the cracking reactions mainly occurring in the chain hydrocarbons. However, to form methane, the methyl radicals produced by the cracking of the chain hydrocarbons require hydrogen with which to bond, which must come from an external source.

Pyrolysis simulations of saturated hydrocarbons have shown that activation energy required for saturated hydrocarbons to crack to gas is relatively high, so this reaction does not occur easily under geological conditions (Hill et al., 2003). Wang et al. (2011) studied the mechanisms and kinetics of pyrolysis of n-dodecane using reactive molecular dynamics (ReaxFF MD) simulation and chemical modeling, and calculated the bond dissociation enthalpies (BDEs) of C–H bonds to produce hydrogen atom and C₁₂H₂₅ radical of n-dodecane (Wang et al., 2011). The BDEs of C–H bonds at different C sites in the n-dodecane molecules require more than 90 kcal/mol, which again confirms that the pyrolysis of n-dodecane will not occur readily.

It therefore follows that an external supply of hydrogen is the main factor affecting the cracking of chain hydrocarbons into methane. Unlike chain hydrocarbons, the high molecular weight organic matter in asphaltene is mostly in form of polycyclic aromatic hydrocarbons (PAHs). It is known that the asphaltene is not easily cracked into small molecular compounds. However, it will condense easily with increasing aromatization of its molecules at high temperatures and will eventually form pyrobitumen with the release of a certain number of hydrogen atoms (Figure 9). These released hydrogen atoms are likely to be an important source of hydrogen radicals, which can then combine with the methyl radicals produced by cracking of chain hydrocarbons to form methane. Consequently, in theory, the presence of asphaltene components supports the cracking of chain hydrocarbons and the generation of methane (Figure 9).

Figure 9.

Cracking of saturated hydrocarbons and polymerization of asphaltenes.

Construction of mixed structure models

In building mixed structural models of saturated hydrocarbons and asphaltenes, a typical asphaltene molecule was used to represent asphaltic fraction (Yen, 1972) and n-tetradecane was used to represent saturated fraction. Three sets of mixed models are constructed, with different molecular numbers and the proportions of asphaltenes reaching at 20%, 50%, and 80% in each respective set of models. Each mixed model system contained 20 n-tetradecane molecules and 1, 4, or 15 asphaltene molecules to provide weight ratios of saturated hydrocarbons to asphaltenes of 8:2, 5:5, and 2:8, respectively. The three multi-molecular models are shown in Figure 10.

Figure 10.

Construction of mixed structure model of saturated hydrocarbons (S) and asphaltenes (A). Notes: (a) S:A = 2:8; (b): S:A = 5:5; (c): S:A = 8:2.

The initial molecular configuration of the unit cell was constructed randomly using the amorphous cell module in Materials Studio 2017. In order to ensure that the initial molecules assemblage in the system is reasonable, geometric optimization was carried out using the Condensed-phase Optimized Molecular Potentials for Atomistic Simulation Studies (COMPASS) force field by Forcite code in the Materials Studio before carrying out molecular dynamics (MD) simulations. The COMPASS force field is suitable for predicting the atomic-level properties of hydrocarbon compounds (Ashraf and van Duin, 2017; Wang et al., 2020).

ReaxFF-MD simulations

To gain an understanding of the thermal degradation processes in these models, a series of simulations was conducted with a reactive force field (ReaxFF) using a large-scale atomic molecular massively parallel simulator (LAMMPS). The molecular ReaxFF, developed by van Duin et al. (2001), can be used to describe bond formation and charge transfers in complex reactive molecular systems. The principle of ReaxFF is set out in the literature (van Duin et al., 2001), and its potential in hydrocarbons pyrolysis modeling has been proved (van Duin et al., 2001; Salmon et al., 2009; Zheng et al., 2013, 2014). ReaxFF MD simulations were performed using constant temperature and volume (NVT) ensembles. The key parameters of pressure and temperature were controlled using a Nose–Hoover barostat and thermostat. NVT MD simulations were then performed at 2000 K. A time step of 0.1 fs, a total simulation time of 500 ps, and a heating rate of 10 K/ps were set. To identify and trace the chemical species and their distributions against the background of the dynamics evolution of the models, the FindMole procedure based on FORTRAN scripts was used to analyze dynamic trajectories (Xue et al., 2017).

The yield of methane molecules was calculated from the types and quantities of products in the simulations (defined methane yield: C₁% = number of CH₄ molecules produced*16/relative molecular weight of the whole system). The results show that the yield of methane molecules increases significantly with increase of asphaltene content in the simulated mixed systems, indicating that the addition of asphaltene promotes the pyrolysis of n-alkanes to produce methane (Figure 11).

Figure 11.

Methane yields of mixtures with various asphaltene content.

Gold-tube pyrolysis experiments of mixed components

Saturated hydrocarbons and asphaltene are separated from the crude oil samples from the Toputai area of the Tarim Basin. The steps were as follows: asphaltenes were precipitated using n-hexane and then isolated by filtration. The resulting n-hexane solutions were then separated into saturated fraction by silica gel/alumina (3:2, w/w) column chromatography with n-hexane as the eluent.

Gold-tube pyrolysis experiments were conducted on the mixed components of the saturated hydrocarbons and asphaltenes at 500 °C under 50 MPa at the Thermal Simulation Laboratory for Petroleum Generation and Expulsion at the State Key Laboratory of Petroleum Resources and Prospecting. A 40-mm-long, 0.25-mm-thick gold tube with an inner diameter of 5.5 mm was used for each experiment. The tubes were pre-sealed at one end with a flame gun and cooled to room temperature. Then, four groups of 30 mg samples of the saturated hydrocarbon and asphaltene mixture, with asphaltene contents of 0%, 20%, 50% and 80%, were loaded into the gold tubes. After loading, the open ends of the tubes were sealed using an argon arc welder.

After ensuring that there was no leakage, the gold tubes were heated to the preset temperature within one hour in an autoclave pressurized to 50 MPa. The autoclave was maintained at the specified temperature and pressure for 72 hours before being left to cool down naturally. Once cooled, the gold tubes were cut open and the gases in the tubes were released and collected. Weight loss from each system was determined by weighing the gold tube mass before and after the experiment. Figure 12 shows that the ratio of weight loss to the mass of saturated hydrocarbon in the simulation systems increases with the increase in the asphaltene content. This again indicates that the presence of asphaltene promotes cracking of saturated hydrocarbon and gas generation.

Figure 12.

The ratio of weight loss to saturated hydrocarbon mass with various asphaltene contents.

Comparing the conditions of deep reservoirs in Sichuan and Tarim basins

The differences of the hydrocarbon phase states of deep to ultra-deep reservoirs between the Tarim and the Sichuan basins is controlled by a range of factors. (I) The Sichuan Basin oil reservoirs accumulated early (before the Late Permian), and then experienced long-term deep burial and high temperatures. The light oils in the Tarim Basin reservoirs accumulated during the Neogene, and have rare opportunity to exposed to sufficiently high temperature to initiate oil cracking. (II) Although the present burial depths and temperatures of the Tarim Basin reservoirs are greater than those in the Sichuan Basin, the Sichuan Basin reservoirs have experienced high temperatures (above 220 °C) in the past, whereas the present reservoir temperature in the Tarim Basin is the highest temperature it has ever been. (III) The importance of the differences in the chemical compositions of the crude oils has not previously been recognized. The results of molecular modeling and gold-tube pyrolysis simulation experiments in this study confirm that asphaltenes can promote the cracking of n-alkanes to generate gas. The normal mature oil of the Sichuan Basin has significantly higher contents of asphaltenes than the high-mature light oil of the Tarim Basin, so the former is easier to crack into gas at high temperature, while the latter has greater thermal stability.

Conclusions

Geological conditions are the main factor controlling the phase states of hydrocarbons. Burial, thermal evolution, hydrocarbon generation, and accumulation histories show that the Sichuan Basin paleo-oil reservoirs formed before the late Permian and then experienced deep burial (>8000 m) and abnormally high temperatures (∼220 °C), whereas the Tarim Basin deep oil reservoirs were charged during the Neogene and have never experienced higher temperature than the present reservoir temperature of <170 °C. This is due to the low geothermal gradient and the absence of abnormally thermal events in the basin's history. The Tarim Basin accordingly has much more favorable geological conditions than the Sichuan Basin for the preservation of liquid oils.

The chemical composition of crude oil is identified as an important factor affecting the phase state of hydrocarbons. MD simulation and gold-tube pyrolysis experiment proved that high contents of asphaltenes can help stimulate the cracking of C₁₄ n-alkanes to generate CH₄. The mature oils in the Sichuan Basin contain relatively high asphaltene contents, resulting in relatively low chemical stability and a tendency for the oil to crack into gas. The deep, high-mature light oils in the Tarim Basin have relatively low asphaltene contents, which is more favorable for the preservation of liquid oil.

Highlights

Confirmed the preservation mechanism of ultra-deep liquid oil in Tarim Basin.

Oil chemical composition is the internal factor for its stability.

Asphaltene provides hydrogen source for hydrocarbon cracking.

High maturity oil containing low asphaltene content has high thermal stability.

Footnotes

Declaration of conflicting interests

The author(s) declared no potential conflicts of interest with respect to the research,authorship,and/or publication of this article.

Funding

The author(s) disclosed receipt of the following financial support for the research,authorship,and/or publication of this article: This work was supported by the National Natural Science Foundation of China (No. 42202134 and No. 42173054) and the National Key Research and Development Program of China (No. 2017YFC0603102).

ORCID iDs

Meijun Li

Nansheng Qiu

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Occurrence of deep liquid oil reservoirs in the Sichuan and Tarim basins as constrained by geological evidences and molecular simulation

Abstract

Keywords

Introduction

Geological settings

Geological evidences

Present burial depths and temperatures of reservoirs

Present burial depth of reservoirs

Present temperature of reservoirs

Burial and thermal evolution histories

Episodes and timing of oil reservoirs

Observations and microthermometry of fluid inclusions

Hydrocarbon generation and accumulation in the Tarim Basin

Hydrocarbon generation and accumulation in the Sichuan Basin

Molecular simulation and gold-tube pyrolysis experiment

Chemical compositions of crude oils changing with the thermal evolution

Construction and molecular simulation of the mixed structure model of saturated hydrocarbons and asphaltenes

Hydrocarbon cracking and polycondensation reactions

Construction of mixed structure models

ReaxFF-MD simulations

Gold-tube pyrolysis experiments of mixed components

Comparing the conditions of deep reservoirs in Sichuan and Tarim basins

Conclusions

Highlights

Footnotes

Declaration of conflicting interests

Funding

ORCID iDs

References