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Abstract

Background and motivation

The Chinese petroleum industry began with the discovery of numerous petroliferous basins in West China (Li, 1995). The first reserves were discovered at the Yumen, Dushanzi, Karamay, Lenghu, and Ichklik oilfields in 1939, 1940, 1955, 1957, and 1958, respectively. West China contains 52 sedimentary basins, together comprising an area of ∼172 × 10⁴ km², with 15 representative proven petroliferous basins (e.g. the Sichuan, Tarim, Ordos, Junggar, Turpan–Hami, and Qaidam basins; Chen and He, 2004).

To introduce the latest advances of petroleum exploration and geology research in these basins, this Special Collection collates approximately 20 papers on this topic. We report new discoveries, data, methodologies, and interpretations, as well as presenting challenges and opportunities pertaining to future resource exploration in the region. Such research has yielded new models and methods that can be applied during further petroleum studies in the area and in similar basins worldwide. The results also help to better define the key opportunities for petroleum development in West China.

Chapter contents

This Special Collection is divided into five chapters: chapters one to four contain studies on individual basins (i.e. the Sichuan, Tarim, Ordos, and Turpan–Hami basins), and the fifth chapter focuses on general methodology.

Formation of natural gas reservoirs in the Sichuan Basin

Much exploration and research has been conducted on the late Neoproterozoic to Late Triassic Sichuan Basin, SW China, providing insights into marine strata, oil-cracking gas reservoirs, microbial carbonates, bioprecursor organisms, dolomite reservoirs, diagenesis, karst processes, and the temperature–pressure evolution of the basin (Du et al., 2014; Ma et al., 2010; Wei et al., 2013; Wu et al., 2017; Zou et al., 2014).

Luo et al. (2018) analyze petroleum accumulation in oil-cracking gas reservoirs in the Sinian Dengying and Cambrian Longwangmiao formations of the Sichuan Basin. The gas field contains old strata (Sinian to Cambrian) and is deep (generally > 4500 m), widely distributed, and contains multiple gas-bearing intervals that represent several gas accumulation types (structural, stratigraphic, and structural–stratigraphic). Such large gas reserves are attributed to the occurrence of high-quality source rocks and the availability of large karst reservoirs. The authors propose that the gas reservoirs formed during three stages: (1) oil reservoir formation during the Triassic; (2) oil cracking during the Cretaceous; and (3) gas re-distribution during the Paleogene. They conclude that the primary factor that controlled gas enrichment was large-scale uplift and suggest that areas of high elevation within the eastern paleo-uplift are favorable for further natural gas exploration. This provides solid data for regional exploration and has implications for the exploration in old strata worldwide.

Song et al. (2018a) discuss the depositional evolution, reservoir characteristics, and controlling factors of microbial carbonates of the Sinian Dengying Formation in the Sichuan Basin. Within dolomite samples, they identified 13 cyanobacteria species, as well as 1 oncolite and 2 stromatolite structures. Based on lithology and structures, they subdivide the Dengying Formation into four members. They then characterize the lithology and thickness of microbial carbonate reservoirs within three of the members, and determine the extent of freshwater and burial dissolution, and hydrocarbon charge. They conclude that the dominant factors responsible for microbial reservoir development include the presence of microbial textures and the development of the Mianyang–Changning intracratonic sag.

Zhu et al. (2018) determine the formation mechanism of high-porosity dolomite reservoirs in the Upper Ordovician Tongzi Formation of the Sichuan Basin. They show that the development of the reservoirs was controlled mainly by dolomitization, syn-sedimentary meteoric erosion, and karstification during the Guangxi movement of tectonic uplifting. Based on these results, they suggest that favorable reservoirs occur within high-energy shoal dolomites of the eastern and southeastern Sichuan Basin, which underwent meteoric erosion, and dolomites of the central paleo-uplift, which underwent subaerial karst formation during the Guangxi movement.

Pang et al. (2018) use thin section observations, total organic carbon analysis, and N₂ gas absorption experiments to characterize organic pores and determine the composition of the bioprecursor organisms in shales of the Upper Ordovician Wufeng and lower Silurian Longmaxi formations of the southern Sichuan Basin. Benthic, benthic–planktonic, and planktonic algae assemblages were observed, from bottom to top, within the formations. Pores within kerogen comprise 13–53% of the total pore volume of the shales. Shales containing benthic algae yielded higher total pore volumes, a larger proportion of mesopores, and more complex pore morphologies than those containing planktonic algae. Shales containing benthic algae and those containing planktonic algae yielded unimodal and multimodal pore size distributions, respectively.

Han et al. (2018) constrain the pore sizes in organic and inorganic minerals, and determine the nature of diagenetic processes that affected shale and kerogen from the Upper Ordovician Wufeng and lower Silurian Longmaxi formations. Reported pore sizes are < 6.5 nm and macropores comprise 14.4–22% of the total pore volume. Relationships among shale composition and pore volume and porosity indicate that micro-mesopores (diameter < 6.5 nm), mesopores (diameter 6.5–50 nm), and macropores (>50 nm) comprise mainly organic matter (OM) pores, OM and intraparticle (intraP) pores associated with carbonate, and interparticle (interP) pores associated with quartz, respectively. The authors conclude that mesopores formed through dissolution, and that macropores represent relic inter pores. With increasing carbonate content, meso- and macropore volumes were observed to increase and decrease, respectively.

Xiao et al. (2018) describe a middle Permian shoal-controlled karstic dolomite reservoir in the northwestern Sichuan Basin. They divide fine-crystalline dolomites of the Qixia Formation into three groups: (1) euhedral–subhedral crystalline dolomite associated with a quasi-stratiform karst system (mean porosity = 3.51%; mean permeability = 3.11 mD); (2) euhedral–subhedral crystalline dolomite associated with a leopard porphyritic karst system (mean porosity = 3.36%; mean permeability = 1.22 mD); and (3) allotriomorphic mosaics of crystalline dolomite associated with relic parent rock fabrics (mean porosity = 0.94%; mean permeability = 0.92 mD). They suggest that further exploration within the Qixia Formation should be conducted based on a shoal-controlled karstification model rather than hydrothermal controlled as previously suggested.

Xu et al. (2018) quantitatively reconstruct the middle Permian thermal and pressure history of the northwestern Sichuan Basin (NWSB). Apatite and zircon (U–Th)/He ages, and zircon fission track and vitrinite reflectance data indicate that the NWSB has underwent gradual cooling, with a heat flow of 70–90 mW/m² in the middle Permian that decreased to a present-day value of ∼50 mW/m². Basin modeling results indicate that oil cracking and rapid tectonic subsidence resulted in the overpressurization of the NWSB during the middle Permian. The pressure evolution during the middle Permian is divided into three stages: (1) a brief overpressure stage (T₂–T₃); (2) an overpressure stage (J₁–K₂); and (3) an overpressure reduction stage (K₂–present).

Liu et al. (2018a) reconstruct the Middle Triassic 3D paleogeomorphology of weathered karst in the Longgang area, Sichuan Basin. They identify three geomorphological units above the Leikoupo Formation, referred to as the karst highlands, karst transitional zone, and karst basin. The karst highlands have a poor reservoir capacity due to long-term exposure above the water table. The karst transitional zone underwent multiple periods of karstification, producing high-quality reservoirs in karst monadnocks but poor reservoirs in karren. The karst basin underwent weak karstification and therefore exhibits a poor reservoir capacity. Paleogeomorphological maps indicate that future exploration should focus on monadnocks.

Yu et al. (2018) use thin section, SEM, XRD, porosity, and permeability analyses to determine the diagenetic processes and reservoir characteristics of the Late Triassic continental Xujiahe Formation tight gas sandstone of the northern Sichuan Basin. The Xujiahe sandstone comprises feldspathic litharenite, litharenite, sublitharenite, and quartzarenite, and yields low porosities (0.79–10.43%; mean = 4.55%) and permeabilities (0.0021–26.001 mD; mean = 0.449 mD). The authors infer that mechanical compaction controlled porosity reduction. Carbonate cement reduced reservoir quality, whereas the presence of quartz cement is correlated with higher porosity and permeability. The effect of grain-coating chlorite on reservoir quality remains unknown. The authors conclude that diagenesis has a greater effect on reservoir quality than does depositional environment.

Formation of oil and natural gas dolomite reservoirs in the Tarim Basin, NW China

Recent studies of petroleum geology and geochemistry on the Tarim Basin have focused on (1) the maturation parameters of crude oil; (2) gas breakthroughs and accumulation in natural gas reservoirs; and (3) the formation of silicified carbonate reservoirs (Gong et al., 2014; Zhang et al., 2015; Zhu et al., 2015).

Liang et al. (2018) use aromatic-hydrocarbon parameters and stable carbon (C) and hydrogen (H) isotopes to determine the maturity of Tazhong crude oils from the Tarim Basin. Their results indicate that the oil is highly mature. Crude oil from the Tazhong No. 1 fault zone yields a wide range of values for maturity parameters (toluene/methyl cyclohexane, dibenzothiophene/phenanthrene, and naphthalene/phenanthrene ratios), whereas that from the Tazhong No. 10 structural zone yields a narrow range of values. These data indicate that the Tazhong No. 1 fault zone is more active than the structural belt and produces geochemically complex oil. Stable carbon and hydrogen isotopic data indicate that toluene was produced during the dehydrogenation of methylcyclohexane in crude oil.

Xia et al. (2018) use prediction models to simulate gas breakthrough characteristics and parameter sensitivities in the Yaha-2 wet gas reservoir in the Tarim Basin. They show that a gas density gradient caused a flow of gas through a highly permeable layer, resulting in a gas breakthrough event. The results of a “design of orthogonal experiment” (DOE) indicate that the timing of gas breakthrough was controlled by the injection/production rate and well spacing. The dimensionless gas breakthrough time and sweep efficiency parameters were controlled mainly by the permeability variation coefficient. The models are also used to calculate the timing of gas breakthrough and sweep volume.

Zhao et al. (2018) determine the hydrocarbon sources and reservoir accumulation mechanisms of wet gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin. Carbon isotopic analyses indicate that natural gas was derived from Jurassic coal measures, whereas oil was derived primarily from Lower Triassic lacustrine rocks; minor coal-derived oil is also observed. Light hydrocarbon component and n-alkane analyses indicate that early trapped oil was later altered by gas washing. Fluids within the reservoir display an atypical distribution, with oil occurring above gas and water, which were locally produced in gas reservoirs in relation to the dynamic accumulation of oil and gas.

You et al. (2018) present a case study of well SN4 in the Tarim Basin and investigate the characteristics and formation mechanisms of silicified carbonate reservoirs. They divide the reservoirs into a lower section of silicified carbonate, a middle section of limestone, and an upper section of silicified carbonate. Silicification temperatures were 150–190°C and porosity ranges from 3% to 20.5%. Secondary calcite yields ⁸⁷Sr/⁸⁶Sr ratios that are higher than those of concurrent seawater and δ¹³C values similar to those of the surrounding limestones, indicating that the hydrothermal fluid was derived from deep clastic sediments or basement, whereas carbon was sourced from limestones. Silicification through interaction with hydrothermal fluids was controlled by movement along strike-slip faults.

Reservoir formation and tight gas accumulation in the Ordos Basin, central West China

The Ordos Basin is a large intracratonic petroliferous basin that hosts the largest gas fields in China (gas reserves > 10¹¹ m³; Chen et al., 2017). Dolomite and tight gas sandstone reservoirs may be targeted during future gas exploration (Li et al., 2016), and therefore recent research has focused on such reservoirs.

Based on sedimentology and geochemistry data, Chen et al. (2018) constrain diagenetic processes and establish a depositional model for dolomite reservoirs of the Middle Ordovician Majiagou Formation in the Ordos Basin. The reservoir was deposited on a semi-restricted platform on a tidal flat, with the peritidal shoal facies distributed along the shoreward side of the central paleo-uplift. Destructive diagenesis (e.g. recrystallisation, cementation, compaction, and pressure solution) and mineral deposition resulted in densification of the dolomites. The physical properties of the dolomite gas reservoirs likely enhanced through dolomitization and dissolution during burial.

Liu et al. (2018b) use thin section, X-ray diffraction, scanning electron microscope, and drill core data to constrain the petrological characteristics of Carboniferous–Permian tight sandstone reservoirs in coal-bearing strata of the Linxing area, along the eastern margin of the Ordos Basin. Dissolution of quartz resulted in an increase in porosity, whereas feldspar dissolution reduced porosity as secondary minerals were produced. The presence of illite, kaolinite, and chlorite reduces porosity and permeability; however, grain-coating chlorite may act to enhance reservoir quality.

Ji et al. (2018) develop an analytical model to characterize the supply and development of natural gas in the Sulige tight reservoirs of the Ordos Basin. The model produces a clear boundary between high- and low-permeability regions, and gas was observed to flow into the latter region. During initial production, gas was extracted primarily from the high-permeability area. Production continued at a pseudo-steady state until a pressure wave reached the boundary between the two regions. A further increase in production resulted in the extraction of gas from the region with low porosity and permeability.

Depositional environments and petroleum geology of the Turpan–Hami Basin, NW China

Recent studies have identified Permian strata within the Turpan–Hami Basin as exploration targets (Zhang et al., 2014). However, the depositional environment during the Permian in the basin is unclear, which has hindered petroleum exploration (Xu et al., 2013). Therefore, the article presented here focuses on depositional environments during the Permian.

Song et al. (2018b) analyze mudstones from the middle Permian Taerlang and upper Permian Quanzijie formations of the Taoshuyuanzi section, northwestern Turpan–Hami Basin to constrain the middle–late Permian paleoenvironment and determine its implications for petroleum exploration. Complex vertical assemblages of the two formations likely resulted from regional tectonism and frequent changes in lake depth. Paleoclimate changed gradually over time, from a hot–dry climate (lower Taerlang Formation) to a humid climate (upper Taerlang to Quanzijie formations). Paleosalinity decreases gradually from the lower Taerlang Formation to the upper Quanzijie Formation. The sediments were deposited in anoxic and semi-saline water during the middle–late Permian. The upper Taerlang Formation was favorable for the accumulation of mudstones with high values of total organic carbon.

General methodologies applied to petroliferous basins in West China

Petroliferous basins in West China contain gypsum-bearing rocks, abundant oil-cracking gas (e.g. the Sichuan and Tarim basins), and igneous-hosted oil and gas fields (e.g. the Sichuan and Tarim basins; Li et al., 2015; Liu et al., 2010; Zhu et al., 2011; Zou et al., 2008). Laboratory simulations in this Special Collection include: (1) simulation of the dissolution of gypsum-bearing rocks; (2) experiments on the cracking and hydrolysis of hydrocarbons; and (3) simulations of the influence of magmatism on hydrocarbon generation.

To constrain the dissolution processes in gypsum-bearing rocks, Hong et al. (2018) conduct experiments on gypsum, limestone, and dolomite that underwent varying degrees of burial and diagenesis with distinct fluid types. Results show that external conditions have little influence on the dissolution of gypsum-bearing rocks, and dissolution increases with temperature and pressure during the early and middle stages of diagenesis instead of deep burial stage. In contrast, the dissolution of limestone and dolomite is strongly controlled by external conditions. Furthermore, increases in temperature and pressure reduce the dissolution rate of limestone, but increase the dissolution rate of dolomite. Therefore, with increasing burial depth, gypsum-bearing rocks and limestone are preserved, whereas dolomite is more rapidly dissolved.

Wang et al. (2018) conduct hydrous and anhydrous isothermal experiments on n-pentanes and n-octadecanes to evaluate the cracking and hydrolysis of hydrocarbons. Gases produced during cracking of n-octadecane at 350°C and 375°C contain methane, ethane, propane, and n-butane. These gasses contain higher wet gas contents than natural gas accumulations, as hydrolysis and oxidation of hydrocarbons were limited during the experiments due to the lack of iron-bearing mineral buffers. Hydrolysis of n-pentane and n-octadecane produced alcohol without alkenes or hydrogen, likely due to the enhanced diffusion rate of hydrogen in fused silica.

Meng et al. (2018) conduct experiments to determine the influence of magmatism on hydrocarbon generation in two scenarios: (1) simultaneous magmatism and hydrocarbon generation and (2) magmatism following hydrocarbon generation. Simultaneous magmatism and hydrocarbon generation promotes the formation of liquid hydrocarbons. When magmatism acts after hydrocarbon generation, gaseous hydrocarbons are also formed. Therefore, exploration in regions that have undergone simultaneous magmatism and hydrocarbon generation should target oilfields, whereas areas where magmatism post-dated hydrocarbon generation may contain both oil and gas.

Footnotes

Acknowledgements

We wish to express our sincere and deepest gratitude to all authors for their contributions to this Special Collection and for their dedication and perseverance during the publication process. We are indebted to the reviewers who helped to evaluate and improve the articles. Special thanks go to Editor-in-Chief Professor Yuzhuang Sun and Publishing Editor Clare Legge. The Collection would not have been possible without their support, expertise, and enthusiasm. We thank Ruchika Agarwal for the kind handling during the production.

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) received no financial support for the research, authorship, and/or publication of this article.

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Special Issue: Advances of petroleum exploration and geology research in West China's petroliferous basins

Abstract

Background and motivation

Chapter contents

Formation of natural gas reservoirs in the Sichuan Basin

Formation of oil and natural gas dolomite reservoirs in the Tarim Basin, NW China

Reservoir formation and tight gas accumulation in the Ordos Basin, central West China

Depositional environments and petroleum geology of the Turpan–Hami Basin, NW China

General methodologies applied to petroliferous basins in West China

Footnotes

Acknowledgements

Declaration of conflicting interests

Funding

References