Fluid Inclusion Evidence for Oil Charge and Cracking in the Cambrian Longwangmiao Dolomite Reservoirs of the Central Sichuan Basin, China

Xiao, Xuewei; Chen, Honghan; Li, Chunquan; Liu, Xiuyan; Wang, Zecheng; Jiang, Hua

doi:https://doi.org/10.1155/2022/3019100

Geofluids

On this page

Abstract Introduction Sampling Results Discussion Conclusions Data Availability Conflicts of Interest Acknowledgments References Copyright Related Articles

Research Article | Open Access

Volume 2022 | Article ID 3019100 | https://doi.org/10.1155/2022/3019100

Fluid Inclusion Evidence for Oil Charge and Cracking in the Cambrian Longwangmiao Dolomite Reservoirs of the Central Sichuan Basin, China

Xuewei Xiao,¹Honghan Chen,¹Chunquan Li,¹Xiuyan Liu,¹Zecheng Wang,²and Hua Jiang²

Academic Editor: Zhiyuan Wang

Received22 Oct 2021

Revised11 Feb 2022

Accepted24 Feb 2022

Published15 Apr 2022

Abstract

The Cambrian Longwangmiao gas reservoirs in the Moxi area of the Sichuan Basin have a complex associated gas accumulation history. Based on core and thin section examination, fluid inclusion analyses and 1-D burial-thermal modelling, the diagenetic evolution and hydrocarbon accumulation processes in the Longwangmiao Formation have been reconstructed. Various diagenetic events were identified, making up a complete pore fill sequence as follows: solid bitumen/dolomite→ nonfluorescent solid bitumen → dolomite → quartz/yellow fluorescent oily bitumen → residual hole. Analyses of oil inclusions and bitumen-bearing inclusions are key to the understanding of the hydrocarbon accumulation processes. The Th values of the aqueous inclusions that are contemporaneous with hydrocarbon inclusions range from 74.3 to 214.3°C. In conjunction with burial-thermal history modelling results, the results indicate that there were two stages of oil charge and three stages of natural gas accumulation in the Longwangmiao carbonate reservoirs. The two stages of oil charge occurred in the Late Silurian and Middle Triassic, respectively. Three gas accumulation events occurred in the Middle to Late Triassic, Middle Jurassic to Early Cretaceous, and Late Cretaceous, respectively.

1. Introduction

The Anyue Gas Field hosts gas reserves exceeding , which makes it the largest monolithic dolomite and integral gas reservoir discovered so far in China [1]. Huge natural gas resources are stored in the Precambrian Dengying Formation and the Lower Cambrian Longwangmiao Formation in the Sichuan Basin. The tectonic evolution of the paleouplift in the central Sichuan resulted in the generation of this extremely large structural-lithological trap. Current gas reservoirs feature a high temperature (137.5 ~ 163.0°C) and a high formation pressure (pressure coefficient in the range of 1.53~1.70). In addition to large volumes of hydrocarbon gas, the Longwangmiao gas reservoirs comprise medium content of H₂S and medium to low content of CO₂ [2–5].

The sets of source shales are mainly developed in the Deyang-Anyue intraplatform trough. Complex overprinting of multiple tectonic-thermal events has led to disputes regarding the hydrocarbon migration and accumulation process. Some researchers theorize that the gas in place is natural gas from late pyrolysis of kerogen [6], other researchers argue that there was a series of oil charging events followed by cracking episodes, where the emplaced oil was thermally broken down into gas [7]. Based on the existence of high-maturity solid bitumen and low-maturity oily bitumen in the Longwangmiao Formation and combined this observation with the carbon isotope compositions of hydrocarbon gas, Shi et al. [8] propose that the Longwangmiao natural gas is primarily sourced from a secondary regional source rock within the Dengying Formation. They further proposed that the oily bitumen may be formed by later phase of oil charge from Silurian source rocks.

Getting the current time and period of oil and gas charging in this area is very difficult because of the complex mechanism of oil and gas generation and multiphase tectonic activities. To improve understanding of the oil charging and cracking processes that led to the formation of the Longwangmiao gas reservoirs, this study mainly focuses on petrological observations and fluid inclusion analyses of 16 samples from 3 wells in the Anyue Gas Field.

2. Geological Setting

During the Late Proterozoic to Early Paleozoic periods, the Sichuan Basin was in a regional tensile tectonic regime environment [9]. This led to the emplacement of a series of carbonate platforms and intraplatform mudstone rich troughs from the Sinian to the Lower Cambrian [10]. The early Cambrian “Paleo-uplift” in the central Sichuan structurally comprised of two uplifts and one depression striking in a NEE direction and located on the east side of the “Weiyuan-Anyue intra-rift trough” which has an approximately N-S trend (Figures 1(a)–1(c)). Following multiepisodic tectonic movements and deformation during the Caledonian, the present-day paleouplift in central Sichuan geometry was finalized before the start of the Permian. Geomorphologically, it is a large, nose-like syndepositional, denuded paleouplift formed by strong compression in the SW-NE direction. On the west side of the uplift, the Carboniferous, Devonian, Silurian, and Ordovician Upper and Middle Systems are not present, they have been removed via erosion [10].

(a)

(b)

(c)

The deposition of the Lower Cambrian was influenced by the early Cambrian uplift in central Sichuan. During the early Cambrian period, the Longwangmiao Formation was mainly deposited in a carbonate platform edge. Sedimentary facies include mixed tidal flats, restricted platforms, open platforms, platform edges, and slopes. The Longwangmiao Formation experienced two transgression-regression cycles and can be divided into two III-level sequences. From bottom to top, it consists of lagoon intraplatform and beach-platform-mixed tidal flat, which correspond to the upper and lower sections of the Longwangmiao Formation (Figure 1(c)) [4]. The depositional environments of the Longwangmiao Formation can be subdivided into one lagoon surrounded by three beaches. One of the beaches is located on the edge of a platform, on the eastern edge of the basin, and the other two beaches are intraplatform and distributed on the east and west sides of the paleolagoon. The paleolagoon has been suggested to contain both restricted platform and open platform sedimentary facies [11].

The high-quality reservoirs of the Longwangmiao Formation in the central Sichuan result from syngenetic dolomitization and interlayer karstification of beach facies [12] superimposed on Caledonian (Carboniferous-Early Permian). Reservoir permeability and porosity were further enhanced by episodes of epigenetic karstification, burial dissolution, and hydrothermal dolomitization. [13]. This resulted in the formation of the complex dolomite reservoir system, with porosity in the form of dissolution pores, cavities, and intercrystalline pores. The current reservoir has an average porosity of 4.28% and an average thickness of 36 m [14].

3. Sampling and Methodology

3.1. Sample Petrography

Sixteen samples were collected from the Cambrian Longwangmiao Formation. Lithologically, most of the samples are dolomite cements in dissolution pores and cavities, with only a few granular dolomites. The list of samples is shown in Table 1.

Fluid inclusion microthermometry was performed on these samples using 100 μm thick, double-polished thin sections. Cathodoluminescence (CL) investigations were carried out using a RELIOTRON III stage, with a gun current of 300-500 μA and an acceleration voltage of 5-8 kV. This work was undertaken in the Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences (Wuhan).

3.2. Fluid Inclusion Analysis

The fluid inclusion microthermometry was undertaken at the Key Laboratory of Tectonics and Petroleum Resources, China University of Geosciences (Wuhan), using a Linkam THMG600 heating-freezing stage. The heating interval selected when determining Th (Th) was 1°C. In other words, Th measurement precision is ±1°C. Fluid inclusion Th is commonly used to delineate the trapping time of oil and gas or the generation timing of alteration minerals in pores in reservoirs, even in the thermally overmature conditions [15–17]. Soft, reactive minerals such as deeply buried carbonate rocks are easily altered, and as a result, fluid inclusion Th may be prone to resetting [18]. The concept of a fluid inclusion assemblage (FIA) proposed by Goldstein and Reynolds [19] was used in the study. FIAs are easy to identify in pores in clasolite and are difficult to define in dolomite-hosted pores as is the case in this study. To qualify as an FIA, randomly distributed fluid inclusions must have been entrapped at the same time. Lu et al. [20] and Chi and Lu [21] proposed that a group of randomly distributed fluid inclusions in the same microdomain (for example a single crystal) can be presumed to comprise an FIA, assuming that they were all entrapped at the same time.

In this paper, fluid inclusions varied less than +/-15°C in Th are treated as belong to the same FIA and are conducted for thermal history interpretation.

4. Results

4.1. Diagenesis

The samples collected and geological observations in this study are listed in Table 1. Lithologically, the cores can be described as syngenetic, penecontemporaneous, fine-grained dolomites, and matrix dolomites. Dissolution pores, cavities, and intercrystalline pores are well developed, some of which has been partially or fully filled with cements and bitumen. (1)The filling sequence of intergranular pores in algal clastic dolomites and intercrystalline pores in the dolomite are shown in Figure 2. Based on the petrographic observations on the cores and thin sections, dissolution cavities are extremely well developed in the Longwangmiao dolomite reservoirs (Figures 2(A1) and 2(A2)). Under polarized light, the dolomite crystals show a foggy core, with bright edges (Figure 2(A3)). Under the cathodoluminescence (CL), the matrix dolomite emits dark red color, while the dolomite cements precipitated in intergranular pores emit scarlet color (Figure 2(A4)). Intercrystalline pores in dolomite are mostly filled by nonfluorescent solid bitumen and quartz (Figures 2(A5) and 2(A6)). A typical example of the pore filling suite in intercrystalline pores would be as follows: dolomite → nonfluorescent solid bitumen → quartz → yellow-fluorescing oily bitumen (Figures 2(A7) and 2(A8)). In intergranular expansion pores, the pore fill types identified included the following: dolomite → nonfluorescent solid bitumen → quartz → residual hole (Figures 2(A9) and 2(A10))(2)Figure 3 shows the pore fillings identified in dissolution cavities in the matrix of fine-crystalline dolomites. Dissolution cavities are extremely well developed (Figures 3(B1), 3(B2), 3(C1), and (C2)). Under plane-polarized light, the dolomite crystals show a foggy core with a bright edge (Figures 3(B3) and 3(C3)). Under CL, matrix dolomite emits dark red color, while dolomite cement precipitated in the intergranular pore emits scarlet color (Figures 3(B4) and (C4)). Pore fill types identified in dissolution cavities include as follows: dolomite → nonfluorescent solid bitumen → residual holes (Figures 3(B5), 3(B6), 3(C5), and 3(C6))(3)Figure 4 shows the pore fill types identified in fractures of fine-crystalline dolomite. High-angle cracks and dissolution cavities are filled with solid bitumen and coarse dolomite cements, showing codirectional growth (Figure 4(D1)). Thin sections show bitumen partially infilling and the coarse dolomite fully infilling cracks and dissolution cavities (Figure 4(D2)). Under plane-polarized light, the dolomite shows a crystalline morphology (Figure 4(D3)). Under CL, the matrix dolomite emits dark red color, the dolomite precipitated in intergranular pores emits scarlet color, and intercrystalline pores are filled with nonfluorescent solid bitumen (Figure 4(D4)). The pore fill types identified in the cracks and fractures included the following: nonfluorescent solid bitumen → dolomite → nonfluorescent solid bitumen

Figure 2

The Longwangmiao Formation Well MX26 4924.28 m. Photos of cores and thin sections from the associated petrological observations. (A1) Algal silt, crystal dolomite with dissolution pores and cavities visible at core scale. (A2) Thin-section scan showing the intercrystalline pores and dissolution cavities of dolomite filled with asphalt. (A3) (-) Powder crystal dolomite with bright edges and a foggy center. (A4) (CL) Crystal showing a ring-shaped structure with intercrystalline pores filled with solid pitch; the foggy center of the crystals glows dark red and the bright edges glow scarlet under cathode light. (A5) (-) and (A6) (UV) Fill suite of intercrystalline pores of fine powder crystal dolomite: Dolomite, nonfluorescent solid pitch. (A7) (-) and (A8) (UV) Pore fill types identified in intercrystalline pores in fine powder crystal dolomite with crystals showing bright edges and foggy centers included the following: dolomite → nonfluorescent solid asphalt → yellow fluorescent oily asphalt. (A9) (-) and (A10) (UV) Pore fill types identified in intercrystalline pores in powder crystal dolomite dissolution pores included the following: dolomite → solid pitch → quartz →residual pores. (-): Plane-polarized light; UV: ultraviolet light; CL: cathodoluminescence.

Figure 3

The Longwangmiao Formation in Well MX22 (4941.83-4943.88 m). Photos of cores and thin sections with accompanying petrological observations. (B1) 4941.83 m, the core petrology is powdery crystal dolomite with dissolution pores and cavities. (B2) Thin-section scans show asphalt partially filling intercrystalline pores and dissolution pores. (B3) (-) and (B4) (CL) Dissolution pore partially infilled with asphalt and residual pores. (B5) (-) and (B6) (UV) Dissolution pore fill suite: a small amount of dolomite → solid asphalt → residual pores. (A5) (-) and (C1) 4943.72-4943.88 m, the core petrology is a fine-grained powder crystal dolomite with bedding parallel dissolution pores. (C2) Observation of thin sections shows rims of asphalt filing dissolution holes. (C3) (-) and (C4) (CL) Dissolution pore fill suite: a small amount of dolomite → solid asphalt → residual pores. (C5) (-) and (C6) (UV) Pore fill types identified in intercrystalline pores in powder crystal dolomite dissolution pores included the following: dolomite → solid asphalt → residual pores. (-): plane polarized light; CL: cathodoluminescence; UV: fluorescence.

Figure 4

The Longwangmiao Formation, Well MX20 (4597.29-4598.73 m,). Cores and thin sections with associated petrological observations. (D1) core sample, high-angle cracks in muddy microcrystalline dolomite filled with solid asphalt+dolomite veins. (D2) Thin section showing partially/fully filled cracks and dissolution holes in asphalt. (D3) (-) and (D4) (CL) Pore fill types identified in cracks and dissolution pores included the following: solid asphalt → dolomite. (-): single-polarized light; CL: cathodoluminescence; UV: fluorescence.

4.2. Results of the Fluid Inclusion Analysis

4.2.1. Petrography

Our petrography features allowed the delineation of five types of hydrocarbon inclusions in the Longwangmiao reservoirs (Figures 5 and 6): (i)gas-liquid two-phase oil inclusion(ii)solid bitumen inclusion(iii)gas-solid inclusion (solid bitumen+gas phase)(iv)pure gas inclusion, and(v)gas-liquid two phase aqueous inclusion

Figure 5

The Longwangmiao Formation Well MX20 (4605.34-4605.59 m). Fluid inclusion micrographs with petrologic and petrographic observations. (G1) Observed from the core, there are dissolution cavities in the massive granular fine powder crystal dolomite. (G2) Thin-slice scan shows that the dissolution cavities of granular dolomite are filled with solid asphalt. (G3) (-) Multigroup crack cutting dissolution hole edge fog-centered bright-edged dolomite. (G4) (UV) Crack captures bright blue+blue fluorescent two-stage secondary oil inclusions, the main peak wavelength of the microscopic fluorescence spectrum () is between 456 and 495 nm; intercrystalline pores/dissolution pores are filled with solid asphalt. (G5) Fog core bright edge fine powder crystal dolomite. (G6) (UV) Capture the blue primary oil inclusions in bright-edged dolomite, . (G7) (-) The pure gas-phase inclusions are captured in the cracks of the dolomite filled with dissolution pores. (G8) (-) Pure gas-phase inclusions and solid pitch+hydrocarbon gas two-phase inclusions. (-): single-polarized light; (UV): fluorescence.

Figure 6

The Longwangmiao Formation Well MX20. Photos of fluid inclusion petrologic and petrographic observation of (H1–H3) (-) 4597.29-4598.73 m, synchronous capture of gas-phase inclusions, bitumen inclusions, and brine inclusions in dolomite under different polarized light multiples. (H4) (UV) Non-gas-phase and bitumen inclusions. (J1), (J3), and (J4) (-) 4618.64-4618.86 m, synchronous capture of gas phase+bitumen inclusions, bitumen inclusions and aqueous inclusions in dolomite displayed at different polarized light multiples. (J2) (UV) Nonfluorescing hydrocarbon inclusions.

The oil inclusions are typically secondary inclusions in the crack-filling dolomite. They show blue-white to blue fluorescence (Figures 5(G3) and 5(G4)). A small fraction of the oil-bearing inclusions are primary inclusions in the late-stage dolomite that emit blue fluorescence (Figures 5(G5) and 5(G6)). The dolomite and quartz cements contain solid bitumen inclusions, gas-solid two-phase inclusions (solid bitumen+gas phase), pure gas inclusions, and gas-liquid two-phase aqueous inclusions (Figures 5(G7) and 5(G8) and Figure 6). Inclusions containing solid bitumen and gas phase are considered to be a product of the thermal cracking of primary oil inclusions under high temperatures. Almost all of primary oil inclusions have been thermally altered and were not observed in their original state.

The results of microbeam fluorescence spectrum of individual oil inclusions show there are stage of oil charging (Figure 7).

4.2.2. Measurement of Fluid Inclusion Composition and Properties

Table 2 shows the results of inclusion Th and salinity analysis in Well MX20. Figure 8 shows a Th histogram of the aqueous inclusions. It shows that the Th of aqueous inclusions in dolomite cements within dissolution cavities and fractures is between 118.4 and 192.3°C. This Th range can be further subdivided into three subranges: 118.4 ~ 137.3°C, 141.1 ~ 165.1°C, and 177.6 ~ 192.3°C, likely reflecting at least three phases of hydrothermal dolomitization. The Th of aqueous inclusions trapped in late-fill quartz reaches up to 214.3°C. The Th values of the blue-white and blue fluorescing, oil inclusions were 65.1°C and 85.7°C, respectively. The Th values of synchronous aqueous inclusions were 74.3°C and 117.5°C, respectively. Salinity showed an inverse relationship with increasing temperature (Table 2).

5. Discussion

5.1. Oil Charge and Gas Accumulation

Studies of diagenetic minerals and fabrics in the reservoir, the petrological evaluation of bitumen, fluid inclusion measurements, and U-Pb dating have been integrated as an effective proxy to temporally constrain the processes of hydrocarbon charge in the Longwangmiao Formation in the Gao-Mo area [8, 22–29]. Unfortunately, there are still several inconsistencies in the timing of hydrocarbon charge, which is partly a result of the selection of different samples and the application of different methodologies. Firstly, petrological observations of cores and thin sections show that the paragenetic sequence of pore filling minerals in the dissolution pores and cavities in the Longwangmiao Formation is as follows: Phase I pores: meteoric water-washed bitumen → Phase II pores: cemented dolomite (Cd) → Phase III pores: hydrothermal saddle dolomite (Sd) → Phase IV pores: bitumen cracked to crude oil → Phase V pores: quartz (and a small amount of authigenic illite, kaolinite, and barite) → Phase VI pores: bitumen cracked to light hydrocarbons → Phase VII pores: oily bitumens. Pores containing meteoric water-washed bitumen (Phase I), quartz (Phase V), and the oily bitumen (Phase VII) are only observed locally; pores containing bitumens cracked to crude oil (Phase IV) and to light hydrocarbons (Phase VI) show no fluorescence [30] and are difficult to distinguish due to the absence of coking structures. The homogenization temperatures (Th) of aqueous inclusions identified in different generations of cement were used to allow the delineation of 4 temperature regimes: 90~120°C, 130~170°C, 180~210°C, and 210~230°C [26–28, 31]. The Th of aqueous pore fluids in quartz cement (Phase V) is usually in the range of 154~195°C [26–28], with a few samples giving temperature in the range of 164~372°C [24]. The results from the Th aqueous inclusion with oil or “bitumen + gas” were combined with burial history studies [32] to allow the identification of hydrocarbon charging events.

As stated above, five hydrocarbon charging events were identified: (i)two phases of oil charge (before the end of the Silurian and the end of the late Permian)(ii)two phases of crude oil, light hydrocarbons or bitumen cracking into gas (Late Triassic to Early Jurassic and Middle Jurassic-Cretaceous)(iii)one phase of natural gas charge (Late Cretaceous) [31]

As a result of hydrothermal alteration, most of the oil inclusions evolved into two-phase inclusions of “bitumen + hydrocarbon gas”. Only a few oil inclusions were preserved in fine crystal dolomite, and these were too small to allow measurement of their maturity [26]. ⁴⁰Ar-³⁹Ar dating of the quartz hosting methane inclusions resulted in an age of Ma, bracketing the time period when the fourth phase of cracked gas accumulation took place [23]. The improved method of Karweil [33] was used to obtain the formation time of epigenetic-reservoir bitumen in the Longwangmiao Formation in well GK1. This gave an age range of 163-157 Ma (Middle Jurassic) [25], which is earlier than the gas generation stage of the Qiongzhusi source rock (Late Jurassic to Early Cretaceous) [34]. Three Re-Os isotopic ages of Ma, Ma, and were obtained from bitumens in the Lower Cambrian Changjianggou Formation in the Kuangshanliang area of the Longmenshan fault belt. These timings represent the emplacement of the Phase I water-washed bitumens) (486 Ma) and the Phase II bitumens cracked to crude oil (172~162 Ma) [22]. Thus far, no isotopic age for the dolomites that host oil inclusions has been obtained. This age would allow the determination of the trapping time of oil inclusions or pores containing “bitumen + hydrocarbon gas” in the Longwangmiao Formation and is critical, because the reservoir gas is primarily derived from in situ crude oils that were cracked to produce light hydrocarbons.

In this paper, the Th data from aqueous inclusions that were trapped at the same time as hydrocarbon inclusions are combined with burial history models to obtain information on oil and gas charge timing [35].

The 1D burial-thermal history curves used in this study for well MX20 were taken from CNPC (Table 3). Heat flows were cited from Liu et al. [36]. Since the aqueous inclusions that are synchronous with hydrocarbon inclusions typically show gas oversaturation such as CH₄, their Th can be considered trapping temperature without the need for pressures correction [37]. Projecting the Th derived from the aqueous inclusions synchronous with the oil, gas, and bitumen inclusions onto a burial history map (Figure 9) gives the following results: (1)Two stages of oil charge: the first stage of oil charge occurred at about 425.0 Ma (Late Silurian); the second stage of oil and gas charge took place at around 241 Ma (Middle Triassic)(2)Three stages of natural gas charge: the first stage of gas accumulation occurred between 238 and 228 Ma (Middle to Late Triassic); the second stage occurred between 173 and 123 Ma (Middle Jurassic to Early Cretaceous); the third stage occurred at 78 Ma (Late Cretaceous)

5.2. Hydrocarbon Accumulation History

On the basis of light hydrocarbon geochemical characteristics and the stable isotopic compositions (δ¹³C and δ²H) of the source rock kerogens and bitumens/biomarkers found in the reservoir, the black shales of the Lower Cambrian Qiongzhusi Formation are considered to be the primary source rock [1].

By Late Silurian, the primary source rock (black shales in the Qiongzhusi Formation) in the Moxi area had not entered the hydrocarbon generation window. However, the first phase of oil inclusions detected in the Longwangmiao reservoirs dates back to this period. This oil charging event is considered to be related to the fact that the Lower Cambrian source rocks formed in the Mianyang-Lezhi-Longchang-Changning trough by the Xingkai rifting entered the hydrocarbon generation window (). This early stage of oil thought to have migrated along unconformity surfaces formed by the Tongwan Movement [38] to the Moxi area. Hydrocarbon generation by this source rock was terminated by tectonic uplift related to the Caledonian orogeny. Both Hao et al. [31] and Gao et al. [30] found the oxidized water-washable bitumen in this period, which is the evidence for early oil charge. Our work related to oil inclusion belonging to this period became the direct evidence for proving the early oil charge time. The sources rocks (i.e., Qiongzhusi shales) were gradually buried by the Emei rifting in the Middle Permian and reentered the hydrocarbon generation kitchen again during the Late Permian to Late Triassic (). The second stage of high-maturity oil inclusion was trapped in the Middle Triassic. During this period, a time of continuous burial, rifting, and associated upwelling of deep hydrothermal fluids occurred. Not only were there multiple phases of emplacement of hydrothermal minerals such as dolomite, but at the same time the bulk of oil accumulated in the Longwangmiao Formation. We also found in well MX39, there were some fluid inclusions including “solid bitumen+gas” (Figure 10), i.e., the result of ancient oil inclusion reset, and its synchronous aqueous inclusion temperature was around 120°C, similar with this period in this study. It is a powerful evidence to support the oil charge time of the second stage (details will be shown in the next paper). With the burial depth of strata and the rise of temperature, a small quantity of oil began to crack into gas and solid bitumen. Diagenetic minerals in the Longwangmiao Formation captured the first phase of pure gas and bitumen inclusions in the Middle to Late Triassic according to their synchronous aqueous inclusion. The average temperature (126.7°C, 131.5°C, and 131.8°C) is relatively lower than oil-cracking temperature. We presume the reason is as follows: there was TSR reaction (i.e., thermochemical sulfate reduction, a process that occurs at elevated temperatures (>120°C) and involves the reaction between sulfate and hydrocarbons to produce hydrogen sulfide, elemental sulfur, calcite, carbon dioxide, and organic sulfur compounds [39, 40, [41] appearing in the Longwangmiao Formation [7, 8, 29], and TSR could improve the occurrence of oil cracking [42], J. E. Dahl et al. [43] also once published a paper which demonstrated that TSR begins oil cracking at about 120-130°C, so albeit the temperature was relatively lower, a small amount of oil could also begin to crack due to the TSR. The second phase of pure gas and bitumen inclusions was trapped in Middle Jurassic to Early Cretaceous. In this period, the temperature was almost greater than 150°C, kerogen entered the threshold of cracking gas, oil continued to crack into gas, and both ubiquitous solid bitumen and stable carbon and hydrogen isotopic compositions of natural gas indicate that a phase of thermally cracking of light hydrocarbons has also occurred [26]. The Longwangmiao Formation in the Moxi area was relatively geologically isolated following this period of cracking of crude oil to gas [38]. From Late Cretaceous, the formation experienced uplift, the gas-water interface was rebalanced leading to the growth of quartz and geometrical constraints. The high temperatures and the presence of transition metals that acted as catalysts would have allowed an intense cracking of light hydrocarbons, and the exchange of methane sourced hydrogen isotopes with H isotopes in formation waters (Rayleigh fractionation in the overmature stage) [26]. The presence of this phenomenon is further supported by the fact that the Th values measured from the aqueous inclusions captured in late precipitated quartz reach up to 214.3°C, synchronous with solid bitumen and gas inclusion, i.e., the third gas collection phase occurred at Late Cretaceous which means the stage of gas reservoir rebalanced (Figure 11). The following should be noted: (1) at the earlier stage, the matter of solid bitumen inclusion may be preoil solid bitumen or postoil solid bitumen, or both [44]; (2) according to Shuai et al. [7], the third stage of gas could be the result from high-over mature shales instead of oil-cracking gas; and (3) most of the gas reservoirs do not exceed the lowest trapping isohypse [45], but a small number do [46], indicating that there must be other factors controlling reservoir fill (for example, strike-slip-related fracturing), but these are beyond the scope of this article.

6. Conclusions

Understanding the complicated accumulation history of the Longwangmiao gas reservoirs in the Moxi area is of great importance to further hydrocarbon exploration in the rift slopes and troughs of this area. Building on previous research and through the studies of reservoir diagenesis and fluid inclusion, the authors draw the following conclusions: (1)The complete fill sequence of the dissolution pores and cavities of the Longwangmiao Formation in the Moxi area is as follows: dolomite containing solid bitumen → nonfluorescing solid bitumen → dolomite → quartz containing yellow-fluorescing oily bitumen → residual pores(2)The Longwangmiao Formation in the Moxi area has experienced two phases of oil charge and three phases of natural gas accumulation. The two phases of oil charge occurred in the Late Silurian and the Middle Triassic. The third phase of natural gas accumulation occurred in the Middle to Late Triassic, Middle Jurassic to Early Cretaceous, and Late Cretaceous(3)Since the natural gas of the Longwangmiao Formation in this area is mainly derived from cracking of paleooils, and the formation was geologically isolated during the oil cracking stage, periods of oil charge represent the reservoir’s main hydrocarbon accumulation periods. This implies that the study of oil inclusions, bitumen-bearing inclusions (altered oil inclusions), and gas inclusions is the key to understanding hydrocarbon accumulation history

It should be noted that the origin of the yellow-fluorescing oily bitumen observed in some dissolution pores is unknown; the host mineralogy of inclusion is a dolomite that has captured many different types of inclusions (solid bitumen inclusions, pure gas inclusions, etc.) and has not been subjected to direct isotopic dating.

Data Availability

The data used to support the findings of this study are included within the article.

Conflicts of Interest

The authors declare that they have no conflicts of interest.

Acknowledgments

This study was funded by the National Key Natural Science Foundation of China “Study on the Coupling Mechanism of Organic Matter, Fluid and Pore Evolution of Cambrian Shale in Southern China” (No. 41730421) and National Science and Technology Major Project “Cambrian-Middle-New Proterozoic Basin Prototype, Source Rocks and Accumulation Conditions Research” (2016ZX05004-001).

References

C. N. Zou, J. Du, C. Xu et al., “Formation, distribution, resource potential, and discovery of Sinian-Cambrian giant gas field, Sichuan Basin, SW China,” Petroleum Exploration and Development, vol. 41, no. 3, pp. 306–325, 2014.
View at: Publisher Site | Google Scholar
W. Liu, N. S. Qiu, Q. C. Xu et al., “The evolution of pore-fluid pressure and its causes in the Sinian-Cambrian deep carbonate gas reservoirs in central Sichuan Basin, southwestern China,” Journal of Petroleum Science and Engineering, vol. 169, pp. 96–109, 2018.
View at: Publisher Site | Google Scholar
G. Q. Wei, J. H. Du, C. C. Xu et al., “Characteristics and accumulation modes of large gas reservoirs in Sinian-Cambrian of Gaoshiti-Moxi region, Sichuan Basin,” Acta Petrolei Sinica, vol. 1, no. 2, pp. 164–177, 2016.
View at: Publisher Site | Google Scholar
X. F. Yang, X. Z. Wang, H. Tang et al., “Reservoir characteristics and main controlling factors of the Longwangmiao Formation in the Moxi area, central Sichuan Basin, China,” Arabian Journal of Geoscience, vol. 9, no. 3, p. 217, 2016.
View at: Publisher Site | Google Scholar
Y. Yueming, Y. Yu, and Y. Guang, “Gas accumulation conditions and key technologies for exploration & development of Sinian and Cambrian gas reservoirs in Anyue gas field,” Acta Petrolei Sinica, vol. 40, no. 4, pp. 493–508, 2019.
View at: Google Scholar
X. W. Tian, G. Y. Hu, W. Li et al., “Geochemical characteristics and significance of Sinian reservior bitumen in Leshan-Longnvsi paleo-uplift area, Sichuan Basin,” Natural Gas Geoscience, vol. 24, no. 5, pp. 982–990, 2013.
View at: Google Scholar
Y. H. Shuai, S. C. Zhang, G. Y. Hu, W. Li, T. Wang, and S. Qin, “Thermochemical sulphate reduction of Sinian and Cambrian natural gases in the Gapshiti-Moxi area, Sichuan basin, and its enlightment for gas sources,” Acta Geologica Sinica, vol. 93, no. 7, pp. 1754–1766, 2019.
View at: Google Scholar
C. H. Shi, J. Cao, X. C. Tan, B. Luo, W. Zeng, and W. Hu, “Discovery of oil bitumen co-existing with solid bitumen in the Lower Cambrian Longwangmiao giant gas reservoir, Sichuan Basin, southwestern China: implications for hydrocarbon accumulation process,” Organic Geochemistry, vol. 108, pp. 61–81, 2017.
View at: Publisher Site | Google Scholar
G. C. Zhao, Y. J. Wang, B. C. Huang et al., “Geological reconstructions of the East Asian blocks: from the breakup of Rodinia to the assembly of Pangea,” Earth-Science Reviews, vol. 186, pp. 262–286, 2018.
View at: Publisher Site | Google Scholar
T. Ma, X. C. Tan, L. Li et al., “Sedimentary characteristics and lithofacies palaeogeography during Longwangmiao period of Early Cambrian, Sichuan Bain,” Acta Sedimentologica Sinica, vol. 34, no. 1, pp. 33–48, 2016.
View at: Publisher Site | Google Scholar
Y. Wei, W. Guoqi, X. Wuren et al., “New understandings of the sedimentation mode of Lower Cambrian Longwangmiao Fm reservoirs in the Sichuan Basin,” Natural Gas Industry, vol. 38, no. 7, pp. 8–15, 2018.
View at: Google Scholar
Y. L. Li, F. R. Wu, D. J. Liu et al., “Distribution pattern and exploration prospect of Longwangmiao Fm reservoirs in the Leshan-Longnüsi Paleouplift, Sichuan Basin,” Natural Gas Industry B, vol. 34, no. 3, pp. 61–66, 2014.
View at: Publisher Site | Google Scholar
H. L. Zeng, W. Z. Zhao, Z. H. Xu et al., “Carbonate seismic sedimentology: a case study of Cambrian Longwangmiao Formation, Gaoshiti-Moxi area, Sichuan Basin, China,” Petroleum Exploration and Development, vol. 45, no. 5, pp. 830–839, 2018.
View at: Publisher Site | Google Scholar
J. G. Zhou, C. C. Xu, G. S. Yao et al., “Genesis and evolution of Lower Cambrian Longwangmiao Formation reservoirs, Sichuan Basin, SW China,” Petroleum Exploration and Development, vol. 42, no. 2, pp. 175–184, 2015.
View at: Publisher Site | Google Scholar
B. Fabrizio, A. Karem, and D. P. Giovanna, “Stable-isotope and fluid inclusion constraints on the timing of diagenetic events in the dolomitized Dolomia Principale inner platform (Norian, Southern Alps of Italy),” Marine and Petroleum Geology, vol. 121, article 104615, 2020.
View at: Publisher Site | Google Scholar
S. Marta and L. Volker, “Fluid inclusion evidence for low-temperature thermochemical sulfate reduction (TSR) of dry coal gas in Upper Permian carbonate reservoirs (Zechstein, Ca2) in the North German Basin,” Chemical Geology, vol. 534, article 119453, 2020.
View at: Publisher Site | Google Scholar
A. Su, H. H. Chen, J. X. Zhao, T. W. Zhang, Y. X. Feng, and C. Wang, “Natural gas washing induces condensate formation from coal measures in the Pinghu Slope Belt of the Xihu Depression, East China Sea Basin: insights from fluid inclusion, geochemistry, and rock gold-tube pyrolysis,” Marine and Petroleum Geology, vol. 118, article 104450, 2020.
View at: Publisher Site | Google Scholar
R. H. Goldstein, “Reequilibration of fluid inclusions in low-temperature calcium-carbonate cement,” Geology, vol. 14, no. 9, pp. 792–795, 1986.
View at: Publisher Site | Google Scholar
R. H. Goldstein and T. Reynolds, “Systematics of fluid inclusions in diagenetic minerals,” SEPM Short Course Notes 31, Society for Sedimentary Geology, 1994.
View at: Google Scholar
Z. Y. Lu, H. H. Chen, H. R. Qing et al., “Petrography, fluid inclusion and isotope studies in Ordovician carbonate reservoirs in the Shunnan area, Tarim basin, NW China: Implications for the nature and timing of silicification,” Sedimentary Geology, vol. 359, pp. 29–43, 2017.
View at: Publisher Site | Google Scholar
G. X. Chi and H. Z. Lu, “Validation and representation of fluid inclusion microthermometric data using the fluid inclusion assemblage (FIA) concept,” Acta Petrologica Sinica, vol. 24, no. 9, pp. 1945–1953, 2008.
View at: Google Scholar
X. Ge, C. B. Shen, D. Selby et al., “Petroleum-generation timing and source in the northern Longmen Shan thrust belt, Southwest China: implications for multiple oil-generation episodes and sources,” AAPG Bulletin, vol. 102, no. 5, pp. 913–938, 2018.
View at: Publisher Site | Google Scholar
L. C. Li, Geochemical Study on Hydrocarbon Accumulation of the Cambrian Formation in the Middle Cambrian of Middle Sichuan, Chengdu University of Technology, 2017.
G. Liu, G. Z. Wang, S. G. Liu, L. Fan, and X. He, “Characteristics and geological significance of fluid inclusions in Longwangmiao Formation of Moxi structure in Central Sichuan, China,” Journal of Chengdu University of Technology (Science & Technology Edition), vol. 41, no. 6, pp. 723–732, 2014.
View at: Google Scholar
J. B. Wang, X. M. Xiao, and R. T. Guo, “Study on the genesis and gas potential of bitumen in early Paleozoic strata of Sichuan basin,” Natural Gas Industry, vol. 23, no. 5, pp. 127–129, 2003.
View at: Google Scholar
W. Wu, B. Luo, W. J. Luo, and W. Wang, “Further discussion about the origin of natural gas in the Sinian of central Sichuan paleo-uplift, Sichuan Basin, China,” Journal of Natural Gas Geoscience, vol. 1, no. 5, pp. 353–359, 2016.
View at: Publisher Site | Google Scholar
F. H. Xu, H. F. Yuan, G. S. Xu, and X. Luo, “Fluid charging and hydrocarbon accumulation in the Cambrian Longwangmiao Formation of Moxi structure, Sichuan Basin, SW China,” Petroleum Exploration and Development, vol. 45, no. 3, pp. 442–451, 2018.
View at: Publisher Site | Google Scholar
H. F. Yuan, M. X. Zhao, G. Z. Wang et al., “Phases of hydrocarbon migration and accumulation in Cambrian Longwangmiao Formation of Moxi structure, Central Sichuan, China,” Journal of Chengdu University of Technology (Science and Technology Edition), vol. 41, no. 6, pp. 694–702, 2014.
View at: Google Scholar
P. W. Zhang, G. D. Liu, C. F. Cai et al., “Alteration of solid bitumen by hydrothermal heating and thermochemical sulfate reduction in the Ediacaran and Cambrian dolomite reservoirs in the Central Sichuan Basin, SW China,” Precambrian Research, vol. 321, pp. 277–302, 2019.
View at: Publisher Site | Google Scholar
P. Gao, L. Guangdi, G. G. Lash, B. Li, D. Yan, and C. Chen, “Occurrences and origin of reservoir solid bitumen in Sinian Dengying Formation dolomites of the Sichuan Basin, SW China,” International Journal of Coal Geology, vol. 200, pp. 135–152, 2018.
View at: Publisher Site | Google Scholar
B. Hao, W. Z. Zhao, S. Y. Hu et al., “Bitumen genesis and hydrocarbon accumulation history of the Cambrian Longwangmiao Formation in Central Sichuan Basin,” Shiyou Xuebao/Acta Petrolei Sinica, vol. 38, no. 8, pp. 863–875, 2017.
View at: Google Scholar
D. A. Karlsen, T. Nedkvitne, S. R. Larter, and K. Bjørlykke, “Hydrocarbon composition of authigenic inclusions: application to elucidation of petroleum reservoir filling history,” Geochimica et Comochimica Acta, vol. 57, no. 15, pp. 3641–3659, 1993.
View at: Publisher Site | Google Scholar
X. M. Xiao, D. H. Liu, and J. M. Fu, “The geological time of hydrocarbon generation and migration is calculated by using bitumen reflectivity,” Chinese Science Bulletin, vol. 45, no. 19, pp. 2123–2127, 2000.
View at: Google Scholar
L. Zhang, G. Wei, X. Z. Li, Z. C. Wang, and X. M. Xiao, “The thermal history of Sinian-Lower Palaeozic high/over mature source rock in Sichuan Basin,” Natural Gas Geoscience, vol. 18, pp. 726–731, 2005.
View at: Google Scholar
H. H. Chen, “Advances in geochronology of hydrocarbon accumulation,” Oil and Gas Geology, vol. 28, no. 2, pp. 143–150, 2007.
View at: Google Scholar
Y. F. Liu, L. J. Zheng, N. S. Qiu, J. Jing-Kun, and C. Qing, “The effect of temperature on the overpressure distribution and formation in the central paleo-uplift of the Sichuan Basin,” Chinese Journal of Geophysics, vol. 58, no. 4, pp. 340–351, 2015.
View at: Publisher Site | Google Scholar
J. Parnell, D. Middleton, H. H. Chen, and D. Hall, “The use of integrated fluid inclusion studies in constraining oil charge history and reservoir compartmentation: examples from the Jeanne d'Arc Basin, offshore Newfoundland,” Marine and Petroleum Geology, vol. 18, no. 5, pp. 535–549, 2001.
View at: Publisher Site | Google Scholar
F. H. Xu, Fluid system and hydrocarbon accumulation of Sinian Dengying Formation and Cambrian Longwangmiao Formation in central Sichuan, Chengdu University of Technology, 2017.
C. F. Cai, R. H. Worden, S. H. Bottrell, L. Wang, and C. Yang, “Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China,” Chemical Geology, vol. 202, no. 1-2, pp. 39–57, 2003.
View at: Publisher Site | Google Scholar
C. F. Cai, C. M. Zhang, H. He, and Y. Tang, “Carbon isotope fractionation during methane-dominated TSR in East Sichuan Basin gasfields, China: a review,” Marine and Petroleum Geology, vol. 48, pp. 100–110, 2013.
View at: Publisher Site | Google Scholar
K. K. Li, S. C. George, C. F. Cai et al., “Fluid inclusion and stable isotopic studies of thermochemical sulfate reduction: Upper Permian and Lower Triassic Gasfields, northeast Sichuan Basin, China,” Geochimica et Cosmochimica Acta, vol. 246, pp. 86–108, 2019.
View at: Publisher Site | Google Scholar
S. C. Zhang, Y. H. Shuai, and G. Y. Zhu, “TSR promotes crude oil cracking to gas: evidence from simulated experiments,” Scientia Sinica (Terrae), vol. 3, pp. 307–311, 2008.
View at: Google Scholar
J. E. Dahl, J. M. Moldowan, K. E. Peters et al., “Diamondoid hydrocarbons as indicators of natural oil cracking,” Nature, vol. 399, no. 6731, pp. 54–57, 1999.
View at: Publisher Site | Google Scholar
D. Misch, D. Gross, G. Hawranek et al., “Solid bitumen in shales: petrographic characteristics and implications for reservoir characterization,” International Journal of Coal Geology, vol. 205, pp. 14–31, 2019.
View at: Publisher Site | Google Scholar
C. Zhang, C. C. Yang, Y. C. Liu, X. Yang, B. Wang, and Z. Zhu, “Controlling factors of fluid distribution in The Lower Cambrian Longwangmiao Formation, Moxi Area, Sichuan Basin,” Geology and Exploration, vol. 53, no. 3, pp. 599–608, 2017.
View at: Google Scholar
Z. C. Wang, T. S. Wang, L. Wen, H. Jiang, and B. Zhang, “Basic geological characteristics and accumulation conditions of Anyue giant gas field, Sichuan basin,” China Offshore Oil and Gas, vol. 28, no. 2, pp. 45–52, 2016.
View at: Google Scholar

Copyright

Copyright © 2022 Xuewei Xiao et al. This is an open access article distributed under the Creative Commons Attribution License, which permits unrestricted use, distribution, and reproduction in any medium, provided the original work is properly cited.

PDF Download Citation

Download other formats

Order printed copies