scholarly journals Geochemical Characteristics of the Lower Cretaceous HengTongshan Formation in the Tonghua Basin, Northeast China: Implications for Depositional Environment and Shale Oil Potential Evaluation

2020 ◽  
Vol 11 (1) ◽  
pp. 23
Author(s):  
Wentong He ◽  
Youhong Sun ◽  
Xuanlong Shan
Keyword(s):  
Organic Matter ◽  
Natural Gas ◽  
Northeast China ◽  
Depositional Environment ◽  
Oil And Gas ◽  
Higher Plants ◽  
Source Rocks ◽  
Shale Oil ◽  
Resource Potential ◽  
Reducing Environment

The Tonghua Basin in Northeast China potentially contains shale oil and gas resources, but the exploration and development of these resources has been limited. The Sankeyushu depression represents the sedimentary center of the Tonghua Basin, and a large thickness of shale, the Hengtongshan Formation, was deposited in this depression. Exploratory engineering discoveries in recent years have confirmed that the Hengtongshan Formation has the potential to produce oil and gas. A series of methods, including inorganic and organic geochemistry and organic petrology, have been used to study the source material, organic matter maturity, depositional environment and oil-generating potential of the Hengtongshan Formation. Investigation of drill core samples has revealed that the Hengtongshan Formation in the Sankeyushu depression is mainly composed of black shale, with a small amount of plant fossils and thin volcanic rocks, and the content of brittle minerals (quartz + carbonate minerals) is high. The provenance of organic matter in the source rocks in the Hengtongshan Formation is a mixture of aquatic organisms (algae and bacteria) and higher plants, and there may be some marine organic components present in some strata.The organic matter was deposited and preserved in a saline reducing environment. Volcanism may have promoted the formation of a reducing environment by stratification of the lake bottom water, and the lake may have experienced a short-term marine ingression with the increase in the salinity. The maturity of the organic matter in all the source rocks in the Hengtongshan Formation is relatively high, and hydrocarbons have been generated. Some source rocks may have been affected by volcanism, and the organic matter in these rocks is overmature. In terms of the shale oil resource potential, the second member of the Hengtongshan Formation is obviously superior to the other members, with an average total organic carbon (TOC) of 1.37% and an average hydrogen index (HI) of 560.93 mg HC/g TOC. Most of the samples can be classified as good to very good source rocks with good resource potential. The second member can be regarded as a potential production stratum. According to the results of geochemical analysis and observations of shale oil and natural gas during drilling, it is predicted that the shale oil is present in the form of a self-sourced reservoir, but the migration range of natural gas is likely relatively large.

scholarly journals THE ORGANIC MATTER CHARACTERISTIC OF LOWER MIOCENE FORMATION IN CUU LONG BASIN

2009 ◽  
Vol 12 (10) ◽  
pp. 78-88
Author(s):  
Luan Thi Bui
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Depositional Environment ◽  
Oil And Gas ◽  
Source Rocks ◽  
Lower Miocene ◽  
South Vietnam ◽  
The Subject ◽  
To Come ◽  
Oval Shape

Cuu Long basin is located mainly in South Vietnam continental shelf and a part of mainland belonging to Mekong estuary area. It has an oval shape, convex seawards and lies along Vung Tau-Binh Thuan coast. Cuu Long basin adjoins mainland northwestwards, separates from Nam Con Son basin by Con Son uplift, southwest part is Khorat - Natuna uplift and northeast part is Tuy Hoa strike-slips separated from Phu Khanh basin. Recent oil and gas quantity exploited from Cuu Long basin is evaluated to be produced dominantly from Oligocene organic-rich sediments. Some studies suggested that organic matter of lower Miocene shale deposits fails to come up to standard of source rock or very poor source rock. Lower Miocene sediments considered how to play a role in providing production into trap is the subject studied more in detailed in this report. The organic carbon (TOC %) in lower Miocene source rocks contains mostly kerogene type III is 0.64-1.32%. The depositional environment of the organic matter in the lower Miocene sediments is terrestral. Therefore the lower Miocene formation may be considered the source rocks, but has not generated hydrocarbon, because it has not passed the oil window. The depositional environment of the organic matter in the lower Miocene sediments is terrestry.

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 Application of the Fractal Method to the Characterization of Organic Heterogeneities in Shales and Exploration Evaluation of Shale Oil

2019 ◽  
Vol 7 (4) ◽  
pp. 88 ◽  
Author(s):  
Bo Liu ◽  
Liangwen Yao ◽  
Xiaofei Fu ◽  
Bo He ◽  
Longhui Bai
Keyword(s):  
Organic Matter ◽  
Vertical Distribution ◽  
Power Law ◽  
Hurst Exponent ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Organic Carbon Content ◽  
Shale Oil ◽  
Box Counting Dimension ◽  
The Vertical Distribution

The first member of the Qingshankou Formation, in the Gulong Sag in the northern part of the Songliao Basin, has become an important target for unconventional hydrocarbon exploration. The organic-rich shale within this formation not only provides favorable hydrocarbon source rocks for conventional reservoirs, but also has excellent potential for shale oil exploration due to its thickness, abundant organic matter, the overall mature oil generation state, high hydrocarbon retention, and commonly existing overpressure. Geochemical analyses of the total organic carbon content (TOC) and rock pyrolysis evaluation (Rock-Eval) have allowed for the quantitative evaluation of the organic matter in the shale. However, the organic matter exhibits a highly heterogeneous spatial distribution and its magnitude varies even at the millimeter scale. In addition, quantification of the TOC distribution is significant to the evaluation of shale reservoirs and the estimation of shale oil resources. In this study, well log data was calibrated using the measured TOC of core samples collected from 11 boreholes in the study area; the continuous TOC distribution within the target zone was obtained using the △logR method; the organic heterogeneity of the shale was characterized using multiple fractal models, including the box-counting dimension (Bd), the power law, and the Hurst exponent models. According to the fractal dimension (D) calculation, the vertical distribution of the TOC was extremely homogeneous. The power law calculation indicates that the vertical distribution of the TOC in the first member of the Qingshankou Formation is multi-fractal and highly heterogeneous. The Hurst exponent varies between 0.23 and 0.49. The lower values indicate higher continuity and enrichment of organic matter, while the higher values suggest a more heterogeneous organic matter distribution. Using the average TOC, coefficient of variation (CV), Bd, D, inflection point, and the Hurst exponent as independent variables, the interpolation prediction method was used to evaluate the exploration potential of the study area. The results indicate that the areas containing boreholes B, C, D, F, and I in the western part of the Gulong Sag are the most promising potential exploration areas. In conclusion, the findings of this study are of significant value in predicting favorable exploration zones for unconventional reservoirs.

COAL AS A SOURCE OF OIL AND GAS: A CASE STUDY FROM THE BASS BASIN, AUSTRALIA

2003 ◽  
Vol 43 (1) ◽  
pp. 117 ◽  
Author(s):  
C.J. Boreham ◽  
J.E. Blevin ◽  
A.P. Radlinski ◽  
K.R. Trigg
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Middle Eocene ◽  
Vitrinite Reflectance ◽  
Mineral Resources ◽  
Sedimentary Basins ◽  
Source Rocks ◽  
Gas Generation ◽  
Australian Context ◽  
Effective Source

Only a few published geochemical studies have demonstrated that coals have sourced significant volumes of oil, while none have clearly implicated coals in the Australian context. As part of a broader collaborative project with Mineral Resources Tasmania on the petroleum prospectivity of the Bass Basin, this geochemical study has yielded strong evidence that Paleocene–Eocene coals have sourced the oil and gas in the Yolla, Pelican and Cormorant accumulations in the Bass Basin.Potential oil-prone source rocks in the Bass Basin have Hydrogen Indices (HIs) greater than 300 mg HC/g TOC. The coals within the Early–Middle Eocene succession commonly have HIs up to 500 mg HC/g TOC, and are associated with disseminated organic matter in claystones that are more gas-prone with HIs generally less than 300 mg HC/g TOC. Maturity of the coals is sufficient for oil and gas generation, with vitrinite reflectance (VR) up to 1.8 % at the base of Pelican–5. Igneous intrusions, mainly within Paleocene, Oligocene and Miocene sediments, produced locally elevated maturity levels with VR up to 5%.The key events in the process of petroleum generation and migration from the effective coaly source rocks in the Bass Basin are:the onset of oil generation at a VR of 0.65% (e.g. 2,450 m in Pelican–5);the onset of oil expulsion (primary migration) at a VR of 0.75% (e.g. 2,700–3,200 m in the Bass Basin; 2,850 m in Pelican–5);the main oil window between VR of 0.75 and 0.95% (e.g. 2,850–3,300 m in Pelican–5); and;the main gas window at VR >1.2% (e.g. >3,650 m in Pelican–5).Oils in the Bass Basin form a single oil population, although biodegradation of the Cormorant oil has resulted in its statistical placement in a separate oil family from that of the Pelican and Yolla crudes. Oil-to-source correlations show that the Paleocene–Early Eocene coals are effective source rocks in the Bass Basin, in contrast to previous work, which favoured disseminated organic matter in claystone as the sole potential source kerogen. This result represents the first demonstrated case of significant oil from coal in the Australian context. Natural gases at White Ibis–1 and Yolla–2 are associated with the liquid hydrocarbons in their respective fields, although the former gas is generated from a more mature source rock.The application of the methodologies used in this study to other Australian sedimentary basins where commercial oil is thought to be sourced from coaly kerogens (e.g. Bowen, Cooper and Gippsland basins) may further implicate coal as an effective source rock for oil.

OIL GEOCHEMISTRY AND POTENTIAL SOURCE ROCKS OF THE OFFICER BASIN, SOUTH AUSTRALIA

1980 ◽  
Vol 20 (1) ◽  
pp. 68 ◽  
Author(s):  
D.M. McKirdy ◽  
A.J. Kantsler
Keyword(s):  
Organic Matter ◽  
Organic Carbon ◽  
Carbonate Rocks ◽  
Depositional Environment ◽  
South Australia ◽  
Source Rocks ◽  
Potential Source ◽  
Playa Lake ◽  
Oil Source ◽  
Extractable Organic Matter

Oil shows observed in Cambrian Observatory Hill Beds, intersected during recent stratigraphic drilling of SADME Byilkaoora-1 in the Officer Basin, indicate that oil has been generated within the basin. Shows vary in character from "light" oils exuding from fractures through to heavy viscous bitumen in vugs in carbonate rocks of a playa-lake sequence.The oils are immature and belong to two primary genetic families with some oils severely biodegraded. The less altered oils are rich in the C13 - C25 and C30 acyclic isoprenoid alkanes. Source beds within the evaporitic sequence contain 0.5 - 1.0% total organic carbon and yield up to 1900 ppm solvent-extractable organic matter. Oil-source rock correlations indicate that the oils originated within those facies drilled; this represents the first reported examples of non-marine Cambrian petroleum. The main precursor organisms were benthonic algae and various bacteria.Studies of organic matter in Cambrian strata from five other stratigraphic wells in the basin reveal regional variations in hydrocarbon source potential that relate to differences in precursor microbiota and/or depositional environment and regional maturation. Micritic carbonates of marine sabkha origin, located along the southeast margin of the basin, are rated as marginally mature to mature and good to prolific sources of oil. Further north and adjacent to the Musgrave Block, Cambrian siltstones and shales have low organic carbon values and hydrocarbon yields, and at best are only marginally mature. Varieties of organic matter recognised during petrographic studies of carbonates in the Officer Basin include lamellar alginite (alginite B) and "balls" of bitumen with reflectance in the range 0.2 to 1.4%.

An integrated organic–inorganic geochemical characterization of Paleogene sediments in No.1 Structural Belt of the Nanpu Sag, Bohai Bay Basin, eastern China: implications for the origin of organic matter

2020 ◽  
Vol 21 (1) ◽  
pp. geochem2019-060
Author(s):  
Yu Guo ◽  
Wenzhe Gang ◽  
Gang Gao ◽  
Shangru Yang ◽  
Chong Jiang ◽  
...  
Keyword(s):  
Organic Matter ◽  
Higher Plants ◽  
Eastern China ◽  
Source Rocks ◽  
Bohai Bay ◽  
Type Ii ◽  
Lacustrine Environment ◽  
Anoxic Conditions ◽  
Supplementary Material ◽  
Nanpu Sag

Paleogene sediments, especially the third member of the Dongying Formation (Ed3) and the first and third members of the Shahejie Formation (Es1 and Es3), have been regarded as the most important source rocks in the Nanpu Sag. Organic and inorganic analyses, including Rock-Eval pyrolysis, gas chromatography-mass spectrometry, and element geochemistry, in 91 mudstone samples, were used to reconstruct the palaeoenvironmental conditions, such as palaeoclimate, palaeo-salinity and palaeo-redox conditions, and to recognize the origin of organic matter. The results show that Es3 has a higher TOC content than Es1 and Ed3. Hydrocarbon genetic potential (S1 + S2) of the samples indicate fair to good hydrocarbon potential. The kerogen type of Ed3 and Es1 source rocks are Type II1–II2, while Es3 source rocks are dominated by Type II2–III kerogens. Biomarkers and inorganic geochemical indicatives of source rocks, such as Pr/Ph, V/(V + Ni) and Cu/Zn, indicate a lacustrine environment with fresh to brackish water under suboxic to anoxic conditions during deposition. Ed3 source rocks are characterized by low G/C30H (gamacerane/C30hopane) (<0.1), TT/C30H (tricyclic terpane/C30hopane) and S/H (serane/hopane), high Pr/Ph (pristane/phytane) and C24TeT/C23TT (C24tetracyclic terpane/C23tricyclic terpane), indicating mixed input of both algae and terrestrial higher plants, dominated by terrestrial higher plants. Es1 source rocks display medium G/C30H, TT/C30H, S/H, Pr/Ph and C24TeT/C23TT, indicative of a mixed input of both algae and terrestrial higher plants. Es3 source rocks are characterized by high G/C30H (>0.1), TT/C30H and S/H, low Pr/Ph and C24TeT/C23TT, typical of a mixed input of algae and terrestrial higher plants, with algal dominance. Ed3, Es1 and Es3 source rocks were mostly deposited in semi-arid to humid-warm climate conditions, with an average temperature higher than 15°C. This study suggests that suitable temperatures, a fresh to brackish lacustrine environment and suboxic to anoxic conditions could result in a high organic matter concentration and preservation, thus providing prerequisites for the formation of high-quality source rocks.Supplementary material: Tables S1–S3 are available at https://doi.org/10.6084/m9.figshare.c.5227684

scholarly journals Use of Geochemical Fossils as Indicators of Thermal Maturation: An Example from the Anambra Basin, Southeastern Nigeria

2015 ◽  
Vol 2015 ◽  
pp. 1-11 ◽  
Author(s):  
Olumuyiwa Adedotun Odundun
Keyword(s):  
Organic Matter ◽  
Oil And Gas ◽  
Land Plant ◽  
Source Rocks ◽  
Chemical Compositions ◽  
Organic Input ◽  
Southeastern Nigeria ◽  
Anambra Basin ◽  
Subsurface Sediments ◽  
Geochemical Studies

Organic geochemical studies and fossil molecules distribution results have been employed in characterizing subsurface sediments from some sections of Anambra Basin, southeastern Nigeria. The total organic carbon (TOC) and soluble organic matter (SOM) are in the range of 1.61 to 69.51 wt% and 250.1 to 4095.2 ppm, respectively, implying that the source rocks are moderately to fairly rich in organic matter. Based on data of the paper, the organic matter is interpreted as Type III (gas prone) with little oil. The geochemical fossils and chemical compositions suggest immature to marginally mature status for the sediments, with methyl phenanthrene index (MPI-1) and methyl dibenzothiopene ratio (MDR) showing ranges of 0.14–0.76 and 0.99–4.21, respectively. The abundance of 1,2,5-TMN (Trimethyl naphthalene) in the sediments suggests a significant land plant contribution to the organic matter. The pristane/phytane ratio values of 7.2–8.9 also point to terrestrial organic input under oxic conditions. However, the presence of C27 to C29 steranes and diasteranes indicates mixed sources—marine and terrigenous—with prospects to generate both oil and gas.

scholarly journals Geochemical Characterization of the Eocene Coal-Bearing Source Rocks, Xihu Sag, East China Sea Shelf Basin, China: Implications for Origin and Depositional Environment of Organic Matter and Hydrocarbon Potential

Minerals ◽  
2021 ◽  
Vol 11 (8) ◽  
pp. 909
Author(s):  
Xiong Cheng ◽  
Dujie Hou ◽  
Xinhuai Zhou ◽  
Jinshui Liu ◽  
Hui Diao ◽  
...  
Keyword(s):  
Organic Matter ◽  
East China Sea ◽  
Water Table ◽  
Depositional Environment ◽  
Source Rocks ◽  
East China ◽  
Gas Chromatography Mass Spectrometry ◽  
Peak Oil ◽  
China Sea ◽  
East China Sea Shelf

Eocene coal-bearing source rocks of the Pinghu Formation from the W-3 well in the western margin of the Xihu Sag, East China Sea Shelf Basin were analyzed using Rock-Eval pyrolysis and gas chromatography–mass spectrometry to investigate the samples’ source of organic matter, depositional environment, thermal maturity, and hydrocarbon generative potential. The distribution patterns of n-alkanes, isoprenoids and steranes, high Pr/Ph ratios, abundant diterpanes, and the presence of non-hopanoid triterpanes indicate predominant source input from higher land plants. The contribution of aquatic organic matter was occasionally slightly elevated probably due to a raised water table. High hopane/sterane ratios and the occurrence of bicyclic sesquiterpanes and A-ring degraded triterpanes suggest microbial activity and the input of microbial organisms. Overwhelming predominance of gymnosperm-derived diterpanes over angiosperm-derived triterpanes suggest a domination of gymnosperms over angiosperms in local palaeovegetation during the period of deposition. The high Pr/Ph ratios, the plot of Pr/n-C17 versus Ph/n-C18, the almost complete absence of gammacerane, and the distribution pattern of hopanes suggest that the samples were deposited in a relatively oxic environment. Generally, fluctuation of redox potential is coupled with source input, i.e., less oxic conditions were associated with more aquatic organic matter, suggesting an occasionally raised water table. Comprehensive maturity evaluation based on Ro, Tmax, and biomarker parameters shows that the samples constitute a natural maturation profile ranging from marginally mature to a near peak oil window. Hydrogen index and atomic H/C and O/C ratios of kerogens suggest that the samples mainly contain type II/III organic matter and could generate mixed oil and gas.

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