Sequential distribution of gas reservoirs in the Hangjinqi area, Ordos Basin, North China: Application of continuous and discontinuous hydrocarbon accumulation mode

2020 ◽  
pp. 1-49
Author(s):  
Haikuan Nie ◽  
Xiaoliang Wei ◽  
Jinchuan Zhang ◽  
Qian Chen ◽  
Guangxiang Liu ◽  
...  
Keyword(s):  
Shale Gas ◽  
Ordos Basin ◽  
Water Soluble ◽  
Source Rocks ◽  
Formation Mechanisms ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Distribution Characteristics ◽  
Gas Reservoirs ◽  
Continuous Accumulation

Gas reservoirs can be divided into two types based on the migration and accumulation processes, and distribution characteristics associated with the reservoirs: continuous accumulation that is within or adjacent to the source rocks and discontinuous accumulation that is in the reservoir rocks. Correspondingly, reservoirs can also be classified as conventional reservoirs, unconventional reservoirs and reservoirs in a transitional state. In order to demonstrate differences and regularities in the distribution characteristics and formation mechanisms of the two accumulation types, the continuous and discontinuous hydrocarbon accumulations in the Hangjinqi area of the Ordos Basin, China, is systematically analyze. Continuous accumulation (coalbed methane, shale gas, basin-centered gas, water-soluble gas) and discontinuous accumulation reservoirs (various traps) are located in the southern and northern regions of the Hangjinqi area, respectively, and they may be changed with the source rock quality, migration force, reservoir capacity and trapping condition. Several factors, such as hydrocarbon generation ability, porosity, and cap rock-trap combinations, are recognized here as essential factors for the formation and current distribution of gas reservoirs in the study area. Understanding the distribution characteristics of continuous accumulation and discontinuous accumulation can predict the potential gas reservoirs types based on discovered gas reservoirs. It is recommended to explore anticline gas reservoirs in the north of Boerjianghaizi fault, and CBM, shale gas and basin-centered gas reservoirs in the south of Boerjianghaizi fault. Though shale gas exploration activity is still lacking in the study area, we believe that the maturity and the burial depth of the marine-continental organic-rich shale in the Permian Shanxi-Taiyuan Formations are suitable for shale gas generation and preservation, indicating further research on the upper Paleozoic shale source rocks is required.

scholarly journals Tectono-thermal Evolution of the Lower Paleozoic Petroleum Source Rocks in the Southern Lublin Trough: Implications for Shale Gas Exploration from Maturity Modelling

2018 ◽  
Vol 35 ◽  
pp. 02002
Author(s):  
Dariusz Botor
Keyword(s):  
Shale Gas ◽  
Vitrinite Reflectance ◽  
Late Carboniferous ◽  
Source Rocks ◽  
Maximum Temperature ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Lower Paleozoic ◽  
Lower Silurian ◽  
Shale Gas Reservoirs

The Lower Paleozoic basins of eastern Poland have recently been the focus of intensive exploration for shale gas. In the Lublin Basin potential unconventional play is related to Lower Silurian source rocks. In order to assess petroleum charge history of these shale gas reservoirs, 1-D maturity modeling has been performed. In the Łopiennik IG-1 well, which is the only well that penetrated Lower Paleozoic strata in the study area, the uniform vitrinite reflectance values within the Paleozoic section are interpreted as being mainly the result of higher heat flow in the Late Carboniferous to Early Permian times and ~3500 m thick overburden eroded due to the Variscan inversion. Moreover, our model has been supported by zircon helium and apatite fission track dating. The Lower Paleozoic strata in the study area reached maximum temperature in the Late Carboniferous time. Accomplished tectono-thermal model allowed establishing that petroleum generation in the Lower Silurian source rocks developed mainly in the Devonian – Carboniferous period. Whereas, during Mesozoic burial, hydrocarbon generation processes did not develop again. This has negative influence on potential durability of shale gas reservoirs.

scholarly journals Fluid inclusions in buried quartz of the Yanchang sandstone in the Jiyuan area, Ordos Basin, China: Implications for basin evolution and petroleum accumulation

2020 ◽  
pp. 014459872097451
Author(s):  
Wenqi Jiang ◽  
Yunlong Zhang ◽  
Li Jiang
Keyword(s):  
Fluid Inclusions ◽  
Ordos Basin ◽  
Homogenization Temperature ◽  
Burial Depth ◽  
Hydrocarbon Generation ◽  
Rock Interaction ◽  
Yanchang Formation ◽  
Reflection Data ◽  
And Migration ◽  
Vitrinite Reflection

A fluid inclusion petrographic and microthermometric study was performed on the sandstones gathered from the Yanchang Formation, Jiyuan area of the Ordos Basin. Four types of fluid inclusions in quartz can be recognized based on the location they entrapped. The petrographic characteristics indicate that fluid inclusions in quartz overgrowth and quartz fissuring-I were trapped earlier than that in quartz fissuring-IIa and fissuring-IIb. The homogenization temperature values of the earlier fluid inclusions aggregate around 80 to 90°C; exclusively, it is slightly higher in Chang 6 member, which approaches 95°C. The later fluid inclusions demonstrate high homogenization temperatures, which range from 100 to 115°C, and the temperatures are slightly higher in Chang 9 member. The calculated salinities show differences between each member, including their regression characteristics with burial depth. Combining with the vitrinite reflection data, the sequence and parameters of fluid inclusions indicate that the thermal history of the Yanchang formation mostly relied on burial. Salinity changes were associated with fluid-rock interaction or fluid interruption. Hydrocarbon contained fluid inclusions imply that hydrocarbon generation and migration occurred in the Early Cretaceous. The occurrence of late fluid inclusions implied that quartz cement is a reservoir porosity-loose factor.

scholarly journals Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China

2018 ◽  
Vol 36 (4) ◽  
pp. 801-819 ◽  
Author(s):  
Shuangfeng Zhao ◽  
Wen Chen ◽  
Zhenhong Wang ◽  
Ting Li ◽  
Hongxing Wei ◽  
...  
Keyword(s):  
Natural Gas ◽  
Tarim Basin ◽  
Oil And Gas ◽  
Northwest China ◽  
Source Rocks ◽  
Coal Measure ◽  
Hydrocarbon Generation ◽  
Gas Reservoirs ◽  
Isotopic Analyses ◽  
Jurassic Coal

The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.

scholarly journals Thermal Maturation Regime Revisited in the Dongying Depression, Bohai Bay Basin, East China

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-17
Author(s):  
Haiping Huang ◽  
Hong Zhang ◽  
Zheng Li ◽  
Mei Liu
Keyword(s):  
Organic Geochemistry ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Burial Depth ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Dongying Depression ◽  
Hydrocarbon Maturation

To the accurate reconstruction of the hydrocarbon generation history in the Dongying Depression, Bohai Bay Basin, East China, core samples of the Eocene Shahejie Formation from 3 shale oil boreholes were analyzed using organic petrology and organic geochemistry methods. The shales are enriched in organic matter with good to excellent hydrocarbon generation potential. The maturity indicated by measured vitrinite reflectance (%Ro) falls in the range of 0.5–0.9% and increases with burial depth in each well. Changes in biomarker and aromatic hydrocarbon isomer distributions and biomarker concentrations are also unequivocally correlated with the thermal maturity of the source rocks. Maturity/depth relationships for hopanes, steranes, and aromatic hydrocarbons, constructed from core data indicate different well locations, have different thermal regimes. A systematic variability of maturity with geographical position along the depression has been illustrated, which is a dependence on the distance to the Tanlu Fault. Higher thermal gradient at the southern side of the Dongying Depression results in the same maturity level at shallower depth compared to the northern side. The significant regional thermal regime change from south to north in the Dongying Depression may exert an important impact on the timing of hydrocarbon maturation and expulsion at different locations. Different exploration strategies should be employed accordingly.

scholarly journals Study on Geochemical Characteristics of tight sandstone gas accumulation in Linxing area

2020 ◽  
Vol 206 ◽  
pp. 01017
Author(s):  
Yangbing Li ◽  
Weiqiang Hu ◽  
Xin Chen ◽  
Litao Ma ◽  
Cheng Liu ◽  
...  
Keyword(s):  
Source Rock ◽  
Ordos Basin ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Light Hydrocarbons ◽  
Tight Sandstone ◽  
Source Type ◽  
Reservoir Type ◽  
Sandstone Reservoir ◽  
Main Component

Based on the comprehensive analysis of the characteristics of tight sandstone gas composition, carbon isotope, light hydrocarbons and source rocks in Linxing area of Ordos Basin, the reservoir-forming model of tight sandstone gas in this area is discussed. The study shows that methane is the main component of tight sandstone gas, with low contents of heavy hydrocarbons and non-hydrocarbons, mainly belonging to dry gas in the Upper Paleozoic in Linxing area. The values of δ13C1, δ13C2 and δ13C3 of natural gas are in the ranges of -45.6‰ ~ -32.9‰, -28.9‰ ~ -22.3‰ and -26.2‰~ -19.1‰, respectively. The carbon isotopic values of alkane gas show a general trend of positive carbon sequence. δ13C1 value is less than -30‰, with typical characteristics of organic genesis. There is a certain similarity in the composition characteristics of light hydrocarbons. The C7 series show the advantage of methylhexane, while the C5-7 series mainly shows the advantage of isoalkane. The tight sandstone gas in this area is mainly composed of mature coal-derived gas, containing a small amount of coal-derived gas and oil-type gas mixture. According to the mode of hydrocarbon generation, diffusion and migration of source rocks in Linxing area, the tight sandstone gas in the study area can be divided into three types of reservoir-forming assemblages: the upper reservoir type of the far-source type (upper Shihezi formation-shiqianfeng formation sandstone reservoir-forming away from source rocks), the upper reservoir type of the near-source type ( the Lower Shihezi formation sandstone reservoir-outside the source rock), and the self-storage type of the source type (Shanxi formation-Taiyuan formation source rock internal sand reservoir).

Liquid hydrocarbon characterization of the lacustrine Yanchang Formation, Ordos Basin, China: Organic-matter source variation and thermal maturity

2017 ◽  
Vol 5 (2) ◽  
pp. SF225-SF242 ◽  
Author(s):  
Xun Sun ◽  
Quansheng Liang ◽  
Chengfu Jiang ◽  
Daniel Enriquez ◽  
Tongwei Zhang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Ordos Basin ◽  
Depositional Environments ◽  
Source Rocks ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Type Ii ◽  
Thermal Maturity ◽  
Yanchang Formation

Source-rock samples from the Upper Triassic Yanchang Formation in the Ordos Basin of China were geochemically characterized to determine variations in depositional environments, organic-matter (OM) source, and thermal maturity. Total organic carbon (TOC) content varies from 4 wt% to 10 wt% in the Chang 7, Chang 8, and Chang 9 members — the three OM-rich shale intervals. The Chang 7 has the highest TOC and hydrogen index values, and it is considered the best source rock in the formation. Geochemical evidence indicates that the main sources of OM in the Yanchang Formation are freshwater lacustrine phytoplanktons, aquatic macrophytes, aquatic organisms, and land plants deposited under a weakly reducing to suboxic depositional environment. The elevated [Formula: see text] sterane concentration and depleted [Formula: see text] values of OM in the middle of the Chang 7 may indicate the presence of freshwater cyanobacteria blooms that corresponds to a period of maximum lake expansion. The OM deposited in deeper parts of the lake is dominated by oil-prone type I or type II kerogen or a mixture of both. The OM deposited in shallower settings is characterized by increased terrestrial input with a mixture of types II and III kerogen. These source rocks are in the oil window, with maturity increasing with burial depth. The measured solid-bitumen reflectance and calculated vitrinite reflectance from the temperature at maximum release of hydrocarbons occurs during Rock-Eval pyrolysis ([Formula: see text]) and the methylphenanthrene index (MPI-1) chemical maturity parameters range from 0.8 to [Formula: see text]. Because the thermal labilities of OM are associated with the kerogen type, the required thermal stress for oil generation from types I and II mixed kerogen has a higher and narrower range of temperature for hydrocarbon generation than that of OM dominated by type II kerogen or types II and III mixed kerogen deposited in the prodelta and delta front.

scholarly journals Geochemical Characteristics of Gas and Flowback Water in Lake Facies Shale: A Case Study From the Junggar Basin, China

2021 ◽  
Vol 9 ◽  
Author(s):  
Lin Zhang ◽  
Dan Liu ◽  
Yongjin Gao ◽  
Min Zhang
Keyword(s):  
Carbon Isotope ◽  
Shale Gas ◽  
Isotope Composition ◽  
Ordos Basin ◽  
Junggar Basin ◽  
Source Rocks ◽  
Flowback Water ◽  
Lucaogou Formation ◽  
The Difference

The chemical and isotopic compositions of the natural gas and the co-produced flowback water from the XJC 1 well in Junggar Basin, China, were analyzed to determine the origin of gases in the Permian Lucaogou Formation (P2l) and the Triassic Karamay Formation (T2k) in the Bogda Mountain periphery area of the Southern Junggar Basin. The value of carbon isotope composition of the P2l lacustrine shale gas in the Junggar Basin was between the shale gas in Chang 7 Formation of Triassic (T1y7) in the Ordos Basin and that in the Xu 5 Formation of Triassic (T3x5) in the Sichuan Basin. The difference in gas carbon isotope is primarily because the parent materials were different. A comparison between compositions in the flowback water reveals that the P2l water is of NaHCO3 type while the T2k water is of NaCl type, and the salinity of the latter is higher than the former, indicating a connection between P2l source rock and the T2k reservoir. In combination with the structural setting in the study area, the gas filling mode was proposed as follows: the gas generated from the lacustrine source rocks of the Permian Lucaogou Formation is stored in nearby lithological reservoirs from the Permian. Petroleum was also transported along the faults to the shallow layer of the Karamay Formation over long distances before it entered the Triassic reservoir.

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