scholarly journals A Novel Redox Indicator based on Relative Abundances of C31 And C32 Homohopanes in the Eocene Lacustrine Dongying Depression, East China

2021 ◽  
Author(s):  
Chong Jiang ◽  
Haiping Huang ◽  
Zheng Li ◽  
Hong Zhang ◽  
Zheng Zhai
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
East China ◽  
Peak Oil ◽  
Dongying Depression ◽  
Anoxic Environments ◽  
Oil Generation ◽  
Shahejie Formation ◽  
The Impact ◽  
Fourth Member

Abstract A suite of oils and bitumens from the Eocene Shahejie Formation (Es) in the Dongying Depression, East China was geochemically characterized to illustrate the impact of source input and redox conditions on the distributions of pentacyclic terpanes. The fourth member (Es4) developed under highly reducing, sulfidic hypersaline conditions, while the third member (Es3) formed under dysoxic, brackish to freshwater conditions. Oils derived from Es4 are enriched in C32 homohopanes (C32H), while those from Es3 are prominently enriched in C31 homohopanes (C31H). The C32H/C31H ratio shows positive correlation with homohopane index (HHI), gammacerane index (G/C30H), and negative correlation with pristane/phytane (Pr/Ph) ratio, and can be used to evaluate oxic/anoxic conditions during deposition and diagenesis. High C32H/C31H ratio (> 0.8) is an important characteristic of oils derived from sulfidic, hypersaline anoxic environments, while low values (< 0.8) indicate non-sulfidic, dysoxic conditions. Extremely low C32H/C31H ratios (< 0.4) indicate strong oxic conditions of coal depsoition. Advantages to use C32H/C31H ratio as redox condition proxy compared to the HHI and gammacerane indexes are wider valid maturity range, less sensitive to biodegradation influence and better differentiation of reducing from oxic environments. Preferential cracking of C35-homohopanes leads HHI to be valid in a narrow maturity range before peak oil generation. No C35 homohopane can be reliably detected in the Es4 bitumens when vitrinite reflectance is > 0.75%, which explains the rare occurrence of high HHI values in Es4 source rocks. Gammacerane is thermally more stable and biologically more refractory than C30 hopane, leading G/C30H ratio more sensitive to maturation and biodegradation than C32H/C31H ratio. Meanwhile, both HHI and gammacerane index cannot differentiate level of oxidation. The C32H/C31H ratio can be applied globally as a novel redox proxy in addition to the Dongying Depression.

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.

The Characteristics of Palaeogeomorphology in Ek1 and the Lower Part of Es4 of the Paleogene in Dongying Depression and its Significance to Petroleum Geology

2012 ◽  
Vol 524-527 ◽  
pp. 226-230
Author(s):  
Li An Liu ◽  
Jian Bo Han
Keyword(s):  
Petroleum Geology ◽  
Alluvial Fans ◽  
The South ◽  
Research Results ◽  
Northern Basin ◽  
Dongying Depression ◽  
Contour Graph ◽  
Shahejie Formation ◽  
Fourth Member

By using the data of drilling and logging and other materials, the contour graph of the thickness of the remnant strata can be worked out. After the compaction restoration of the graph, the original sedimentary thickness of the First Member of Kongdian Formation(Ek1) and the Lower Part of the Fourth Member of Shahejie Formation ( lower Es4) can be obtained and their palaeogeomorphology can be reconstructed. The research results show that palaeogeomorphology has an obvious control on the sedimentary systems of Ek1 and lower Es4. In the areas with higher mountains and steeper slopes in the northern basin, there mainly develop nearshore subaqueous fans while in the south of the basin, there mostly develop alluvial fans.

Hydrocarbon generation and evolution of the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China

2018 ◽  
Vol 6 (4) ◽  
pp. SN11-SN21
Author(s):  
Zhenkai Huang ◽  
Maowen Li ◽  
Quanyou Liu ◽  
Xiaomin Xie ◽  
Peng Liu ◽  
...  
Keyword(s):  
Activation Energy ◽  
Eastern China ◽  
Source Rocks ◽  
Bohai Bay ◽  
Hydrocarbon Generation ◽  
Bohai Bay Basin ◽  
Jiyang Depression ◽  
Generation Threshold ◽  
Oil Generation ◽  
Shahejie Formation

Systematic organic petrology and geochemistry analyses have been conducted in the source rocks of the lower Es3 and upper Es4 members of the Shahejie Formation in the Niuzhuang Sub-sag, Jiyang Depression, Bohai Bay Basin, eastern China. The results indicate that the main organic types of shale and nongypsum mudstone in the lower Es3 and upper Es4 member are I-II1 kerogen, and the predominant ([Formula: see text]) activation energy frequencies range from 57 to [Formula: see text]. The similar distribution characteristics in the two source rocks indicate that they have a similar hydrocarbon maturation process. An extensive pyrolysis analysis indicates that the source rocks of the upper Es4 member do not have an obvious double peak hydrocarbon generation model. Previous studies indicate that the hydrocarbon index peak at a depth of 2500–2700 m is affected by migrating hydrocarbon. Major differences are not observed in the hydrocarbon generation and evolution process of the shale and nongypsum mudstone. The primary oil generation threshold of the lower Es3 and upper Es4 members is approximately 3200 m, and the oil generation peak is approximately 3500 m. The activation energy distribution of the gypsum mudstone of the upper Es4 member is wider than that of the shale and nongypsum mudstone, and lower activation energies account for a larger proportion of the activation energies. The above factors may lead to a shallower oil generation threshold for gypsum mudstone compared with that for shale and nongypsum mudstone.

STABLE HYDROGEN ISOTOPE RATIOS OF SEDIMENTARY HYDROCARBONS: A POTENTIAL METHOD FOR ASSESSING THERMAL MATURITY?

2005 ◽  
Vol 45 (1) ◽  
pp. 253
Author(s):  
D. Dawson ◽  
K. Grice ◽  
R. Alexander
Keyword(s):  
Vitrinite Reflectance ◽  
Potential Method ◽  
Source Rocks ◽  
Crude Oils ◽  
Thermal Maturity ◽  
Peak Oil ◽  
Data Set ◽  
High Maturity ◽  
The Difference ◽  
Hydrogen Isotope Ratios

A relationship has been identified between the maturity level of source rocks and the stable hydrogen isotopic compositions (δD) of extracted saturated hydrocarbons, based on the analysis of nine sediments and five crude oils from the Perth Basin (WA). The sediments cover the immature to late mature range. Distinct δD signatures are observed for the immature sediments where pristane and phytane are significantly depleted in deuterium (D) relative to the n-alkanes. With increasing maturity the difference between the δD values of n-alkanes and isoprenoids reduces as pristane and phytane become progressively enriched in D. The n-alkane–isoprenoid δD signature of the crude oils, including one from a different source facies, is similar to mature–late mature sediments representative of the peak oil–generative window. Enrichment of D in isoprenoids is attributed to isotopic exchange associated with thermal maturation. Average δD values of pristane and phytane correlate well with vitrinite reflectance, as does the biomarker maturity parameter Ts/Tm. The limited data set suggests that δD values of aliphatic hydrocarbons may be useful for establishing thermal maturity, particularly when other maturity parameters are not appropriate. Furthermore, we suggest δD values may be useful over a wider maturity range than traditional parameters, particularly at very high maturity where biomarker parameters are no longer effective.

GEOLOGY AND HYDROCARBON POTENTIAL OF THE SOUTHERN GEORGINA BASIN, AUSTRALIA

2001 ◽  
Vol 41 (1) ◽  
pp. 139 ◽  
Author(s):  
G.J. Ambrose ◽  
P.D. Kruse ◽  
P.E. Putnam
Keyword(s):  
Early Carboniferous ◽  
Source Rocks ◽  
Peak Oil ◽  
Middle Cambrian ◽  
Late Cambrian ◽  
Oil Generation ◽  
World Class ◽  
Lower Palaeozoic ◽  
Southwestern Margin ◽  
Intracratonic Basin

The Georgina Basin is an intracratonic basin on the central-northern Australian craton. Its southern portion includes a highly prospective Middle Cambrian petroleum system which remains largely unexplored. A plethora of stratigraphic names plagued previous exploration but the lithostratigraphy has now been rationalised using previously unpublished electric-log correlations and seismic and core data.Neoproterozoic and Lower Palaeozoic sedimentary rocks of the southern portion of the basin cover an area of 100,000 km2 and thicken into two main depocentres, the Toko and Dulcie Synclines. In and between these depocentres, a Middle Cambrian carbonate succession comprising Thorntonia Limestone and Arthur Creek Formation provides a prospective reservoir-source/seal couplet extending over 80,000 km2. The lower Arthur Creek Formation includes world class microbial source rocks recording total organic carbon (TOC) values of up to 16% and hydrocarbon yields up to 50 kg/tonne. This blanket source/seal unconformably overlies sheetlike, platform dolostone of the Thorntonia Limestone which provides the prime target reservoir. Intra- Arthur Creek high-permeability grainstone shoals are important secondary targets.In the Toko Syncline, Middle Cambrian source rocks entered the oil window during the Ordovician, corresponding to major sediment loading at this time. The gas window was reached prior to structuring associated with the Middle Devonian-Early Carboniferous Alice Springs Orogeny, and source rocks today lie in the dry gas window. In contrast, high-temperature basement granites have resulted in overmaturity of the Arthur Creek Formation in the Dulcie Syncline area. On platform areas adjacent to both these depocentres source rocks reached peak oil generation shortly after the Alice Springs Orogeny; numerous structural leads have been identified in these areas. In addition, an important stratigraphic play occurs in the Late Cambrian Arrinthrunga Formation (Hagen Member) on the southwestern margin of the basin. Key elements of the play are the pinchout of porous oil-stained, vuggy dolostone onto basement where top seal is provided by massive anhydrite while underlying Arthur Creek Formation shale provides a potential source.

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.

PETROLEUM SOURCE ROCKS IN THE ROPER GROUP OF THE MCARTHUR BASIN: SOURCE CHARACTERISATION AND MATURITY DETERMINATIONS USING PHYSICAL AND CHEMICAL METHODS

1994 ◽  
Vol 34 (1) ◽  
pp. 279 ◽  
Author(s):  
Dennis Taylor ◽  
Aleksai E. Kontorovich ◽  
Andrei I. Larichev ◽  
Miryam Glikson
Keyword(s):  
Organic Matter ◽  
Chemical Evolution ◽  
Oil And Gas ◽  
Source Rocks ◽  
Type I ◽  
Peak Oil ◽  
Gas Generation ◽  
Oil Generation ◽  
Physical And Chemical ◽  
Extractable Organic Matter

Organic rich shale units ranging up to 350 m in thickness with total organic carbon (TOC) values generally between one and ten per cent are present at several stratigraphic levels in the upper part of the Carpentarian Roper Group. Considerable variation in depositional environment is suggested by large differences in carbon:sulphur ratios and trace metal contents at different stratigraphic levels, but all of the preserved organic matter appears to be algal-sourced and hydrogen-rich. Conventional Rock-Eval pyrolysis indicates that a type I-II kerogen is present throughout.The elemental chemistry of this kerogen, shows a unique chemical evolution pathway on the ternary C:H:ONS diagram which differs from standard pathways followed by younger kerogens, suggesting that the maturation histories of Proterozoic basins may differ significantly from those of younger oil and gas producing basins. Extractable organic matter (EOM) from Roper Group source rocks shows a chemical evolution from polar rich to saturate rich with increasing maturity. Alginite reflectance increases in stepwise fashion through the zone of oil and gas generation, and then increases rapidly at higher levels of maturation. The increase in alginite reflectance with depth or proximity to sill contacts is lognormal.The area explored by Pacific Oil and Gas includes a northern area where the Velkerri Formation is within the zone of peak oil generation and the Kyalla Member is immature, and a southern area, the Beetaloo sub-basin, where the zone of peak oil generation is within the Kyalla Member. Most oil generation within the basin followed significant folding and faulting of the Roper Group.

THE PETROLEUM POTENTIAL OF THE GUNNED AH BASIN AND OVERLYING SURAT BASIN SEQUENCE, NEW SOUTH WALES

1988 ◽  
Vol 28 (1) ◽  
pp. 218 ◽  
Author(s):  
D.S. Hamilton ◽  
C.B. Newton ◽  
M. Smyth ◽  
T.D. Gilbert ◽  
N. Russell ◽  
...  
Keyword(s):  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Lower Permian ◽  
Petroleum Potential ◽  
Shallow Marine ◽  
North West ◽  
South Wales ◽  
Oil Generation ◽  
Origin Of Oil ◽  
Auto Fluorescence

The Permo-Triassic Gunnedah Basin has good potential for the discovery of commercial petroleum. Gas shows have been reported from the Porcupine-Watermark, Black Jack and Digby Formations, and from the basal sandstone of the Purlawaugh Formation in the overlying Surat Basin sequence. Gas flowed on drill stem test from the Porcupine-Watermark Formation in the Wilga Park No. 1 discovery well although the find was sub-commercial. An oil show was observed in Lower Permian volcanics, and oil staining has been observed in the Pilliga Sandstone in several wells. The origin of oil staining in the Pilliga Sandstone is unknown, however, and may have been the result of diesel contamination during drilling operations.Structural style within the basin sequence is characterised by north-south and north-north-west/south- south-east trending anticlines which formed in response to periodic compressive and left lateral strike-slip movements along the main Hunter Mooki Thrust Fault. These anticlines are attractive exploration targets.Westerly-derived quartz-rich sandstones occur at several stratigraphic levels within the Black Jack Formation and within the upper Digby Formation. Sandstones of the western bed-load fluvial system (lower Black Jack Formation) are most prospective with thick sections (up to 8 m) giving permeabilities from several hundred to several thousand millidarcies. Marine reworked easterly-derived sandstones up to 12 m thick in the Black Jack and Watermark Formations have minor reservoir potential with permeabilities in the order of tens of millidarcies. All potential reservoirs within the sequence are considered to be adequately sealed. Regionally extensive shaly units deposited either by marine incursion or lacustrine inundation overlie most reservoir horizons; remaining reservoirs are capped by intraformational shales.Organic petrology and geochemistry indicate the best potential source rocks within the Gunnedah Basin are floodplain, lacustrine and shallow marine facies of the Purlawaugh, Napperby, Watermark, Maules Creek and Goonbri Formations. The shallow marine Arkarula Sandstone Member within the Black Jack Formation also has significant potential for oil generation. Vitrinite reflectance, liptinite auto-fluorescence and TAI values indicate Lower Permian sediments are marginally mature to mature for oil generation. Combining the data on source quality and quantity with thermal maturity, the Permian sediments - in particular the Watermark Formation - have the best potential for generating oil.

Geochemical characterization of the source rock intervals, Beni-Suef Basin, West Nile Valley, Egypt

2021 ◽  
Vol 13 (1) ◽  
pp. 1536-1551
Author(s):  
Nader A. A. Edress ◽  
Saudy Darwish ◽  
Amir Ismail
Keyword(s):  
Heat Flow ◽  
Source Rock ◽  
High Heat ◽  
Source Rocks ◽  
Nile Valley ◽  
Peak Oil ◽  
Burial History ◽  
Depth Limit ◽  
Oil Generation ◽  
Rock Depth

Abstract Geochemical and lithological investigations in the WON C-3X well record five organic-matter-rich intervals (OMRIs) of effective source rocks. These OMRIs correspond to moderate and good potentials. Two of these intervals occurred within the L-Kharita member of the Albian age represent 60.97% of the entire Albian thickness. The rest of OMRIs belongs to the Abu-Roash G and F members of the Late Cenomanian–Santonian age comprising 17.52 and 78.66% of their total thickness, respectively. The calculated heat flow of the studied basin is high within the range of 90.1–95.55 mW/m2 from shallower Abu-Roash F to deeper L-Kharita members. This high-heat flow is efficient for shallowing in the maximum threshold expulsion depth in the studied well to 2,000 m and active source rock depth limit to 2,750 m. Thermal maturity and burial history show that the source rock of L-Kharita entered the oil generation from 97 Ma till the late oil stage of 7.5 Ma, whereas the younger Abu-Roash G and F members have entered oil generation since 56 Ma and not reached peak oil yet. Hence, the source rock intervals from Abu-Roash F and G are promising for adequate oil generation.

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