Petroleum charge history of deeply buried carbonate reservoirs in the Shuntuoguole Low Uplift, Tarim Basin, west China
Introduction
Deep reservoirs in petroliferous basins generally refer to those with depths exceeding 4500 m (Dyman et al., 2002). Marine carbonate reservoir is an important frontier field of deep oil and gas exploration, and has been widely discovered in giant basins around the world (Zappaterra, 1994; Wandrey and Vaughan, 1997; Dyman et al., 2002; Halbouty, 2003; Biteau et al., 2006). In China, significant progress in deep marine carbonate oil and gas exploration has also been made (Sun et al., 2013; Jia et al., 2015; Guo et al., 2019; Zhu et al., 2019; Li et al., 2020), with discoveries of a series of large- and medium-sized deep oil and gas fields, including the Tahe and Tazhong oil and gas fields in the Tarim Basin, the Puguang and Yuanba gas fields in the Sichuan Basin and the Jingbian gas field in the Ordos Basin. However, deep marine carbonate petroleum systems are commonly characterized by multiple sets of source rocks with high maturity, and multiple petroleum generation, migration and accumulation processes, thus making the evolution history of oil and gas reservoirs quite intricate (Dyman et al., 1997; Zhao et al., 2003; Zhu et al., 2019). Petroleum charge history reconstruction has always been a Gordian knot in the study of deep marine carbonate reservoirs and is also the focus of academia and industry. Oil-bearing fluid inclusions occurring in petroleum reservoirs are small aliquots of geofluids entrapped in rock-forming minerals, such as quartz, feldspar and calcite (Goldstein and Reynolds, 1994; Munz, 2001). With the establishment and development of fluid inclusion analysis techniques and methods (Munz, 2001; Volk et al., 2019), fluid inclusion analysis has been widely used in determining palaeo temperature and pressure condition of petroleum reservoirs (Aplin et al., 1999; Thiéry et al., 2000) and timing of petroleum migration and accumulation (Karlsen et al., 1993; Oxtoby et al., 1995; Bhullar et al., 1999). Different from reservoir oils, inclusion oils can record the composition information at the time of entrapment and are free from subsequent alterations, including biodegradation, water washing, hydrocarbon mixing and composition change caused by temperature and pressure (Volk et al., 2019). Therefore, detailed oil-bearing fluid inclusion analysis in deep carbonate oil and gas reservoir can offer an opportunity to trace the geochemical fingerprints of petroleum charged at different times and unravel the mysteries in the petroleum charge history.
The recent discovery of the Shunbei (SB) Oilfield in 2016, which is located immediately southwest of the Tahe Oilfield, is a major breakthrough in deep marine carbonate oil and gas exploration in the Tarim Basin for the past decade (Jiao, 2018; Gu et al., 2019; Qi, 2020). There are significant differences between the Shunbei and Tahe oilfields in terms of tectonic regimes, reservoir types and petroleum physical properties (Gu et al., 2020). For example, influenced by multi-stage petroleum charges, the petroleum physical properties of the Tahe Oilfield exhibit a systematic change from super-heavy and heavy oil in the north to medium-light oil and condensate oil in the south, whereas the petroleum properties of the Shunbei Oilfield are dominated by light to volatile oil (Jiao, 2018; Gu et al., 2020). Oils in the Tahe Oilfield were charged in the middle-late Caledonian (463.2–414.9 Ma), late Hercynian (312.9–268.8 Ma) and Himalayan (22.0–4.8 Ma), with the late Hercynian being the main charge period (Chen et al., 2014; Gu et al., 2020). In contrast, few studies have been carried out to reconstruct the petroleum charge history of the Shunbei Oilfield to date, greatly impeding petroleum exploration and development in the area. In the present study, systematic molecular geochemical correlations of reservoir oils and oil components (free oils and quasi-inclusion oils) from reservoir rocks, fluid inclusion analysis and basin modelling are carried out to reconstruct the petroleum charge history of the Shunbei Oilfield and to gain an in-depth understanding of the formation and burial history of deep marine carbonate reservoirs in the Tarim Basin and elsewhere. This study may offer new insights into deep and old marine carbonate oil and gas exploration around the world.
Section snippets
Geological setting
The Tarim Basin, covering an area of approximately 560 × 103 km2 (Fig. 1a), is the largest inland petroliferous basin in China (Li et al., 1996; Jia and Wei, 2002). It is a giant superimposed basin overlying a continental crust basement, composed mainly of a Paleozoic marine craton basin and a Meso-Cenozoic continental foreland basin (Jia and Wei, 2002). The basin has gone through seven-stage tectonic evolution (Li et al., 1996), and the craton region comprises ten first-order tectonic units (
Samples and methods
A total of 10 reservoir oil samples were selected from key reservoir intervals of ten wells in the study area (Fig. 1c and Table 1). All the target reservoir intervals are at burial depths of 7255.70 m–7650.64 m. Ten core samples in the Yijianfang Formation (O2yj) were collected from the oil-bearing carbonate rocks of the SB2 and SB5 wells, with burial depths ranging from 7331.27 m to 7447.00 m. The core samples are mainly of grainstones, packstones and algal boundstones.
The analytical
Physical properties of reservoir oils
The reservoir oils in the SB Oilfield can be classified as light oil (Table 1). The API gravity of the reservoir oils ranges from 38.8 °API to 46.7 °API. The sulfur and wax content of the reservoir oils is in the range of 0.03%–0.21% and 3.19%–9.89%, respectively. The gas/oil ratio (GOR) ranges from 72 m3/m3 to 582 m3/m3. Based on the differences of physical properties (API gravity, density and viscosity), the reservoir oils can be further subdivided into two types: Oil A and Oil B. Oil A is
Petroleum geochemical characteristics
The pristane/phytane ratios for the studied reservoir oils, free oils and quasi-inclusion oils are generally less than 1 with the exception of the SB1–6H reservoir oil (Table 2), indicating that the source rocks were deposited predominantly under anoxic conditions (Didyk et al., 1978; Peters et al., 1995, 2005). The cross plot of pristane/n-C17 and phytane/n-C18 ratios (Fig. 8a) manifests that the source rock was deposited under a reducing condition with the organic matters being dominated by
Conclusions
Based on molecular geochemical correlations of reservoir oils and oil components (free oils and quasi-inclusion oils) from reservoir rocks, fluid inclusion analysis and basin modelling results, some key findings can be summarized as follows.
- (1)
According to the differences of physical properties (API gravity, density and viscosity) of reservoir oils, two types of reservoir oils have been identified in the Shunbei Oilfield: Oil A and Oil B.
- (2)
Molecular parameters derived from steranes, terpanes and
Author contribution
Peng Yang: Conceptualization, Methodology, Data curation, Formal analysis, Investigation, Writing – original draft, Writing – review & editing. Keyu Liu: Supervision, Writing – review & editing; Jianliang Liu: Visualization, Investigation, Formal analysis. Shuang Yu: Visualization, Formal analysis. Biao Yu: Visualization, Formal analysis. Maoguo Hou: Visualization, Formal analysis; Luya Wu: Resources.
Declaration of competing interest
The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper.
Acknowledgements
This study is supported by the National Key Research and Development Program of China (Grant No. 2019YFC0605500), the Strategic Priority Research Program of the Chinese Academy of Sciences (Grant No. XDA14010401) and National Natural Science Foundation of China (Grant No. 41821002).
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