Stable carbon isotopes of alkane gases from the Xujiahe coal measures and implication for gas-source correlation in the Sichuan Basin, SW China

doi:10.1016/j.orggeochem.2009.01.012

Organic Geochemistry

Volume 40, Issue 5, May 2009, Pages 638-646

https://doi.org/10.1016/j.orggeochem.2009.01.012 Get rights and content

Abstract

The Upper Triassic Xujiahe Formation in the Sichuan Basin, SW China consists of a series of coal measures. The first, third and fifth members of this formation are dominated by gas prone dark mudstones and coals. The mudstones contain Type II and III kerogens with average organic carbon contents around 1.96%. These source rocks are mature in the central Sichuan and highly mature in the western Sichuan Basin, characterized by gas generation with subordinate amounts of light oil or condensate oils. The source rocks are intercalated with the sandstone dominated second, fourth and sixth members of the Xujiahe Formation, thus leading to three separate self contained petroleum systems in the region. The proven gas reserves in the Xujiahe Formation are only less than that of the Triassic Feixianguan Formation and the Xujiahe Formation has the second largest gas field (Guang’an gas field) in the basin. Gases derived from the Xujiahe Formation coals generally show a normal stable carbon isotopic trend for C₁–C₄ n-alkanes, with the highest δ¹³C₂ values among the nine gas pay zones in the basin (−20.7‰ to −28.3‰), and δ¹³C₁ values as low as −43.0‰ in the central Sichuan. Gas accumulations with an oil leg have also been found in the eastern and southern Sichuan where the thickness of the Xujiahe Formation is significantly reduced. Gases in these accumulations tend to show low δ¹³C₂ values (−30.0‰ to −36.3‰), characteristic of oil prone source rocks.

Introduction

This study focuses on the gas geochemistry of the Upper Triassic Xujiahe Formation in the Sichuan Basin, SW China. This Phanerozoic basin has the most stable tectonics in China, delimited by the terrestrial Xujiahe Formation, with an area of 180,000 km² (Wang et al., 2002). The cumulative recoverable reserves in this basin have reached 842 billion m³ by the end of 2005 (Wang et al., 2008). This basin contains the largest number of gas fields in China (127), and had an annual gas production about 17 billion m³ in 2007 (Yang et al., 2008).

Section snippets

Geological setting

The Sichuan Basin can be divided into east, south (including south and southwest), west and central Sichuan gas–oil accumulation zones (Fig. 1). Gases are produced from 21 stratigraphic horizons, ranging from Sinian to Jurassic in age, and the dominant pay zones are in the Sinian Dengying Formation (Z₂d), Carboniferous Huanglong Formation (C₂h), Permian Maokou (P₁m) and Changxing formations (P₂ch), Triassic Feixianguan (T₁f), Jialingjiang (T₁j), Leikoupo (T₂l) and Xujiahe (T₃x) formations and

Analytical methods

The molecular composition of gas samples was determined using an Agilent 6890N gas chromatograph equipped with a flame ionization detector and a thermal conductivity detector, at the PetroChina Research Institute of Petroleum Exploration and Development-Langfang (RIPED-Langfang). Individual hydrocarbon gas components (C₁–C₅) were separated using a capillary column (PLOT Al₂O₃ 50 m × 0.53 mm). Noble gases were separated using two capillary columns (PLOT Molsieve 5 Å 30 m × 0.53 mm, PLOT Q 30 m × 0.53 mm). GC

Results and discussion

Empirical studies of the gas geochemistry in the Sichuan Basin (Wang, 1994) and in many other Chinese sedimentary basins (Dai et al., 2005) suggested a cut off point in the δ¹³C₂ value (−29‰) for differentiating the origin of thermogenic gases in China, with greater values indicating coal derived gases and lower values for oil associated gases. Utilizing this criterion, two types of gases produced from the Xujiahe Formation reservoirs in the Sichuan Basin can be recognized: (a) self-sourced

Conclusions

The Upper Triassic Xujiahe coal measures in the Sichuan Basin contain Types II and III gas prone dark mudstones and coals in the first, third and fifth members, with the sandstone reservoirs in the second, fourth and sixth members forming three separate gas payzones. Most of these gases were derived within the coal measures, leading to the formation of Guang’an, the second largest gas field in the basin. These coal derived gases display a normal stable carbon isotope trend for C₁–C₄ alkanes,

Acknowledgements

We thank Dr. Maowen Li of Geological Survey of Canada for constructive suggestions and extensive editing of an earlier version of this manuscript and Wei Li for generously providing us some analytical data.

References (32)

C. Cai et al.
Thermochemical sulphate reduction and the generation of hydrogen sulphide and thiols (mercaptans) in Triassic carbonate reservoirs from the Sichuan Basin, China
Chemical Geology
(2003)
J. Dai et al.
Origins of partially reserved alkane δ¹³C values for biogenic gases in China
Organic Geochemistry
(2004)
J. Dai et al.
Significances of studies on natural gas geology and geochemistry for natural gas industry in China
Petroleum Exploration and Development
(2008)
E.M. Galimov
Isotope organic geochemistry
Organic Geochemistry
(2006)
R. Patience
Where did coal all the coal gas go?
Organic Geochemistry
(2003)
Y. Chen et al.
Geochemical features of natural gas and the progress of Upper Triassic hydrocarbon accumulation in Middle Sichuan area
Natural Gas Geoscience
(2007)
S. Chen et al.
Source rock conditions and resource potential analysis of reef flat gas reservoirs in Northern Sichuan Basin
Natural Gas Exploration and Development
(2007)
J. Dai
Natural gas and oil formation during coal formed
Petroleum Exploration and Development
(1979)
J. Dai
Distribution, classification and origin of natural gas with hydrogen sulphide in China
Acta Sedimentologica Sinica
(1985)
J. Dai et al.
Carbon isotope characteristics of natural gas in the Sichuan Basin, China
Petroleum Geology and Experiment
(2001)

J. Dai et al.

The problems in natural gas exploration and development in China

J. Dai et al.

Causation of partly reversed orders of δ¹³C in biogenic alkane gas in China

Oil and Gas Geology

(2003)

J. Dai et al.

Development trends of natural gas industry and the significant progress on natural gas geological theories in China

Natural Gas Geoscience

(2005)

R. Fan et al.

Carbon isotopic geochemistry and origin of natural gases in the southern part of the western Sichuan depression

Acta Geoscientica Sinica

(2005)

F. Hao

Evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the Pugang gas field, Sichuan Basin, China

American Association of Petroleum Geologists Bulletin

(2008)

G. Hu et al.

Carboniferous Gas Fields in High Steep Structures of Eastern Sichuan, China

(1997)

Cited by (114)

Intramolecular carbon isotope of propane from coal-derived gas reservoirs of sedimentary basins: Implications for source, generation and post-generation of hydrocarbons
2024, Geoscience Frontiers
An intramolecular isotopic study was conducted on natural gases collected from coal-derived gas reservoirs in sedimentary basins of China to determine their position-specific isotope distributions. The propane from the Turpan-Hami Basin exhibited negative Δ_C-T (δ¹³C_central-δ¹³C_terminal) values ranging from −3.9‰ to −0.3‰, with an average of −2.1‰. Propane from the Ordos Basin, Sichuan Basin, and Tarim Basin showed positive Δ_C-T values, with averages of 1.3‰, 5.4‰ and 7.6‰, respectively. Position-specific carbon isotope compositions reveal the precursors and the propane generation pathways in the petroliferous basins. Propane formed from the thermal cracking of Type III kerogen has larger δ¹³C_central and δ¹³C_terminal values than propane from Type I/II kerogen. The precursor for natural gases collected in this study is identified to be Type III kerogen. Comparing our data to calculated results for thermal cracking of Type III kerogen, we found that propane from the low-maturity gas reservoir in the Turpan Basin was generated via the i-propyl radical pathway, whereas propane from the Sulige tight gas reservoir in the Ordos Basin was formed via the n-propyl radical pathway. δ¹³C_terminal values covered a narrow range across basins, in contrast to δ¹³C_central. The terminal carbon position in propane is less impacted by microbial oxidation and more relevant to maturity levels and precursors. Thus, δ¹³C_terminal has a good potential to infer the origin and maturity level of natural gas. In examining post-generation processes, we proposed an improved identification strategy for microbial oxidation of natural gases, based on the position-specific carbon isotope distributions of propane. Samples from the Liaohe Depression of the Bohai Bay Basin and the Sichuan Basin were detected of post-generation microbial oxidation. Overall, position-specific carbon isotope composition of propane provides new insights into the generation mechanism and post-generation processes of natural gas in the geological period at the atomic level.
A novel method for quantitatively identifying driving forces and evaluating their contributions to oil and gas accumulation
2024, Geoscience Frontiers
Different driving forces govern the formation of distinct types of oil and gas accumulation and yield diverse oil and gas distributions. Complex oil and gas reservoirs in basins are commonly formed by the combination of multiple forces. It is very difficult but essential to identify driving forces and evaluate their contributions in predicting the type and distribution of oil and gas reservoirs. In this study, a novel method is proposed to identify driving forces and evaluate their contribution based on the critical conditions of porosity and permeability corresponding to buoyancy-driven hydrocarbon accumulation depth (BHAD). The application of this method to the Nanpu Sag of the Bohai Bay Basin shows that all oil and gas accumulations in the reservoirs are jointly formed by four driving forces: buoyance (I), non-buoyance (II), tectonic stress (III₁) and geofluid activity (III₂). Their contributions to all proven reserves are approximately 63.8%, 16.2%, 2.9%, and 17.0%, respectively. The contribution of the driving forces is related to the depth, distance to faults and unconformity surfaces. Buoyancy dominates the formation of conventional reservoirs above BHAD, non-buoyant dominate the formation of unconventional reservoirs below BHAD, tectonic stress dominates the formation of fractured reservoirs within 300 m of a fault, and geofluids activity dominates the formation of vuggy reservoirs within 100 m of an unconformity surface.
Gas source of the Middle Jurassic Shaximiao Formation in the Zhongjiang large gas field of Western Sichuan Depression: Constraints from geochemical characteristics of light hydrocarbons
2024, Energy Geoscience
The Zhongjiang gas field is a typical large gas field in terrigenous strata of the Western Sichuan Depression. It remains debatable which member of the Upper Triassic Xujiahe Formation served as the source rocks and how significant the member contributed to the gas accumulations in the Zhongjiang gas field. In this study, we analyzed the essential characteristics of the Lower Jurassic source rocks and the geochemical features of light hydrocarbons in natural gas from the 2nd (T₃x²) and 4th members (T₃x⁴) of the Upper Triassic Xujiahe Formation (T₃x), as well as the Middle Jurassic Shaximiao (J₂s) and Qianfoya (J₂q) formations. Based on this, we explored the sources of the natural gas in the Zhongjiang gas field and determined the natural gas migration patterns and their effects on the properties of light hydrocarbons in the natural gas. The results indicate that the Lower Jurassic lacustrine source rocks of the Zhongjiang gas field contain humic organic matter, with vitrinite reflectance (R_o) values ranging from 0.86% to 0.98%. Samples meeting the criterion for effective source rocks [total organic carbon (TOC) content ≥0.75%] exhibited an average TOC content of merely 1.02%, suggesting significantly lower hydrocarbon generation potential than source rocks in the underlying T₃x, which show higher thermal maturity and TOC contents. For natural gas samples from T₃x², T₃x⁴, J₂s, and J₂q reservoirs, their C_5–7 iso-alkane content was significantly higher than their n-alkane content, and their methylcyclohexane (MCH) index ranged from 59.0% to 77.3%, indicating the predominance of methylcyclohexane in C₇ light hydrocarbons. As indicated by the origin identification and gas-source correlation based on the geochemical features of light hydrocarbons, the natural gas in the Zhongjiang gas field is typical coal-derived gas. The gas from the primary pay zone of the Shaximiao Formation, with significantly high K₁, (P₂ + N₂)/C₇, and P₃/C₇ values, predominantly originated from the 5th member of the T₃x and migrated in the free phase, with a small amount possibly sourced from the Lower Jurassic source rocks. The dissolution and adsorption during gas migration led to a decrease in the aromatic content in C_6–7 light hydrocarbons and an increase in the iso-heptane values. Therefore, their effects must be considered when determining the gas origin and thermal maturity based on the aromatic content in C_6–7 light hydrocarbons and iso-heptane values.
Tight gas accumulation caused by overpressure: Insights from three-dimensional seismic data in the western Sichuan Basin, southwest China
2023, Geoenergy Science and Engineering
Tight gas is an important unconventional gas resource, but numerous aspects of its accumulation and the distribution of high-quality reservoirs remain unclear. The Mesozoic–Cainozoic strata in the Sichuan Basin in southwest China are a focus for tight gas exploration, but have a complex pore pressure distribution that makes exploration challenging. In this study, the pore pressure in Upper Triassic and Jurassic strata in the West Sichuan Depression was predicted from three-dimensional seismic data using the Fillippone method. The results indicate that overpressure has developed in the Upper Triassic Xujiahe Formation in the Xinchang Structural Belt, with pressure coefficients of 1.2–2.4, which are highest in the third member, moderate in the fourth and fifth members, and lowest in the second member. Faults have a significant effect on the pore pressure. Overpressure along regional primary faults is typically weak, but it increases with distance from the faults. The overpressure resulted from disequilibrium compaction and hydrocarbon generation during the Mesozoic, and was intensified and modified by the Himalayan Orogeny. We infer that differential overpressure in tight sandstones is a key factor in gas migration and accumulation. Weakly overpressured zones along primary faults are dominant gas accumulation zones. Secondary faults and related fractures have a limited effect on overpressure, but improve the physical properties of reservoirs by increasing the permeability and promoting water–rock interactions. We suggest that the areas with relatively low pressure around faults and fractures are the most favourable targets for hydrocarbon exploration in tight sandstones.
Overpressure and gas charging in tight sandstone: Xujiahe Formation, northeastern Sichuan Basin
2022, Petroleum Science
Overpressure is a key factor for oil and gas charging in tight reservoirs, but it is still a challenge to evaluate the overpressure evolution and its control on oil and gas charging. Taking Xujiahe Formation in the northeastern Sichuan Basin as an example, this paper presented a method for evaluating overpressure and its effect on natural gas charging in tight sandstone in compressional basin. The abnormally high pressure and its causes were analyzed by measured data and logging evaluation. Theoretical calculation and PVT simulation were used to investigate the amounts of overpressure resulted from hydrocarbon generation and tectonic compression, respectively. Then the source rock - reservoir pressure differences were calculated and the characteristics of natural gas charging during the natural gas charging periods were analyzed. It was revealed that hydrocarbon generation and tectonic compression were the main causes of the overpressure. The overpressure of both source rocks and reservoir exhibited a gradually increasing trend from Middle Jurassic to Early Cretaceous (J₂-K₁), then decreased since Later Cretaceous (K₂), and some of that preserved to now. The contributions of the hydrocarbon generation and tectonic compression to overpressure were different in different periods. The residual pressure difference between the source rocks and the reservoir is the major driving force for tight sandstone gas charging. The main hydrocarbon generating area of the source rocks and the area of high driving force were major natural gas enrichment areas, and the driving force determined the natural gas charging space in the pore throat system of the reservoir. This research helps evaluate the overpressure and pressure difference between source rocks and reservoir in compressed basin, as well as investigate the effective pore throat space of tight gas charging by the driver of overpressure.
Seasonal variations of geofluids from mud volcano systems in the Southern Junggar Basin, NW China
2022, Science of the Total Environment
Variations in the chemical composition of geofluids and of gas fluxes are significant parameters for understanding mud volcanism and correctly estimate their emissions in carbon species, particularly greenhouse gas, methane. In this study, muddy water and gas samples were collected from the Anjihai, Dushanzi, Aiqigou, and Baiyanggou mud volcanoes in the southern Junggar Basin during the four seasons, around a year. This region hosts the most active mud volcanism throughout China. Gas and water were analyzed for major molecular compositions, carbon and hydrogen isotopes of the gas phase, as well as cations and anions, hydrogen and oxygen isotopes of water. The emitted gases are dominated by CH₄ with some C₂H₆, CO₂, and N₂. The seasonal changes in the chemical composition and carbon isotopes of emitted gases are not significant, whereas clear variations in the amounts of cations and anions dissolved in the water are reported. These are higher in spring and summer than autumn and winter. The CH₄, CO₂, and C₂H₆ fluxes are 157.3–1108 kg/a, 1.8–390.1 kg/a, and 10.2–118.7 kg/a, respectively, and a clear seasonal trend of the gas seepage flux has been observed. In January, the macro-seepage flux of open vents is ≥65 % higher than in April, whereas the micro-seepage flux significantly decreased, probably due to the frozen shallow ground and blockage of soil fractures around the vents by heavy snow and ice during January. This probably causes an extra gas pressure transferred to the major vents, resulting in higher flux of the macro-seepage in the cold season. However, the total flux of the whole mud volcano system is generally consistent around a year.

View all citing articles on Scopus

View full text

Stable carbon isotopes of alkane gases from the Xujiahe coal measures and implication for gas-source correlation in the Sichuan Basin, SW China

Abstract

Introduction

Section snippets

Geological setting

Analytical methods

Results and discussion

Conclusions

Acknowledgements

Chemical Geology

Organic Geochemistry

Petroleum Exploration and Development

Organic Geochemistry

Organic Geochemistry

Geochemical features of natural gas and the progress of Upper Triassic hydrocarbon accumulation in Middle Sichuan area

Natural Gas Geoscience

Source rock conditions and resource potential analysis of reef flat gas reservoirs in Northern Sichuan Basin

Natural Gas Exploration and Development

Natural gas and oil formation during coal formed

Petroleum Exploration and Development

Distribution, classification and origin of natural gas with hydrogen sulphide in China

Acta Sedimentologica Sinica

Carbon isotope characteristics of natural gas in the Sichuan Basin, China

Petroleum Geology and Experiment

The problems in natural gas exploration and development in China

Causation of partly reversed orders of δ13C in biogenic alkane gas in China

Oil and Gas Geology

Development trends of natural gas industry and the significant progress on natural gas geological theories in China

Natural Gas Geoscience

Carbon isotopic geochemistry and origin of natural gases in the southern part of the western Sichuan depression

Acta Geoscientica Sinica

Evidence for multiple stages of oil cracking and thermochemical sulfate reduction in the Pugang gas field, Sichuan Basin, China

American Association of Petroleum Geologists Bulletin

Carboniferous Gas Fields in High Steep Structures of Eastern Sichuan, China

Causation of partly reversed orders of δ¹³C in biogenic alkane gas in China