scholarly journals A source rock evaluation of the Mesozoic Sediments of the Well Hyllebjerg-1 Danish Subbasin

1988 ◽  
Vol 9 ◽  
pp. 1-105
Author(s):  
Birthe J Schmidt
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Geothermal Gradient ◽  
Organic Content ◽  
Lower Jurassic ◽  
Source Rocks ◽  
Marginal Areas ◽  
Algal Material ◽  
Clay Formation ◽  
Promising Source

The source rock potential of Mesozoic sediments (cuttings) from the Hyllebjerg 1 well, Danish Subbasin, has been assessed using a number of different petrographical and organochemical methods. Upper Jurassic sediments (Bream Formation) equivalent to the principal source rocks of the North Sea graben structures (Kimmeridge Clay Formation and lateral equivalents) do not show similar prominent source rock characteristics in this well, although a higher proportion of algal material is observed. Sediments with the most promising source rock characteristics for liquid hydrocarbons were· detected mainly in the lower- Jurassic sequences of the upper Fjerritslev Format ion (F-4 and upper F-3 Member) and in one horizon in the Upper Cretaceous Vedsted Formation which showed a good quality composition and a relatively high content of organic matter. But these sediments may be excluded as actual source rocks in this well as maturity (assuming the threshold value near 0. 60 % R ) is first reached at approximately 8500' 0 depth i.e. at the top of the Gassum Formation (Upper Triassic/ Lower Jurassic). The conditions may only by slightly different off - structure is this area, as the F-4 and F-3 Member sequence according to seismic sections is found at approximately the same depth. But the depth to ( and the thickness of) the Fjerritslev Formation is increasing towards the SE into the rimsynclines of the saltdomes nearby. While sufficient maturity is reached in the deeper part of the well, no commercial accumulations of hydrocarbons were encountered. This is attributed to the mainly reworked, unfavourable type of organic matter and the generally decreasing organic content downwards in the well, approaching the lower 1 imi t for potential source rocks ( set at O, 5% TOC). However, generation and migration of small amounts of gaseous hydrocarbons from Gassum Formation sediments containing more humic-influenced organic matter with only minor reworking cannot generally be excluded either here or elsewhere in the basin. Some more attention should also be paid to the Vinding Formation sediments which contain some algae- ri eh ( Botryocous-type) oil-prone horizons of more favourable source rock conditions. Mature sediments are found at shallower depths ( 8500 ') in this well in the central part of the basin compared to the more marginal areas (8900') where a slightly higher geothermal gradient in Jiyllebjerg 1 ( 28°C/km uncorrected) is seen compared with the marginal areas (23.5°C/km uncorrected) away from the basinal depocenter. The basinal depocenter also has a higher heat flow.

scholarly journals Effective source rock selection and oil–source correlation in the Western Slope of the northern Songliao Basin, China

2021 ◽  
Vol 18 (2) ◽  
pp. 398-415
Author(s):  
He Bi ◽  
Peng Li ◽  
Yun Jiang ◽  
Jing-Jing Fan ◽  
Xiao-Yue Chen
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Thermal Evolution ◽  
Songliao Basin ◽  
Source Rocks ◽  
Crude Oils ◽  
Western Slope ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

AbstractThis study considers the Upper Cretaceous Qingshankou Formation, Yaojia Formation, and the first member of the Nenjiang Formation in the Western Slope of the northern Songliao Basin. Dark mudstone with high abundances of organic matter of Gulong and Qijia sags are considered to be significant source rocks in the study area. To evaluate their development characteristics, differences and effectiveness, geochemical parameters are analyzed. One-dimensional basin modeling and hydrocarbon evolution are also applied to discuss the effectiveness of source rocks. Through the biomarker characteristics, the source–source, oil–oil, and oil–source correlations are assessed and the sources of crude oils in different rock units are determined. Based on the results, Gulong and Qijia source rocks have different organic matter primarily detrived from mixed sources and plankton, respectively. Gulong source rock has higher thermal evolution degree than Qijia source rock. The biomarker parameters of the source rocks are compared with 31 crude oil samples. The studied crude oils can be divided into two groups. The oil–source correlations show that group I oils from Qing II–III, Yao I, and Yao II–III members were probably derived from Gulong source rock and that only group II oils from Nen I member were derived from Qijia source rock.

scholarly journals Source rock characterization of mesozoic to cenozoic organic matter rich marls and shales of the Eratosthenes Seamount, Eastern Mediterranean Sea

2018 ◽  
Vol 73 ◽  
pp. 49 ◽  
Author(s):  
Sebastian Grohmann ◽  
Susanne W. Fietz ◽  
Ralf Littke ◽  
Samer Bou Daher ◽  
Maria Fernanda Romero-Sarmiento ◽  
...  
Keyword(s):  
Organic Matter ◽  
Mediterranean Sea ◽  
Source Rock ◽  
Eastern Mediterranean ◽  
Source Rocks ◽  
Eastern Mediterranean Sea ◽  
Potential Source Rock ◽  
Levant Basin ◽  
Rock Characterization ◽  
Rock Eval

Several significant hydrocarbon accumulations were discovered over the past decade in the Levant Basin, Eastern Mediterranean Sea. Onshore studies have investigated potential source rock intervals to the east and south of the Levant Basin, whereas its offshore western margin is still relatively underexplored. Only a few cores were recovered from four boreholes offshore southern Cyprus by the Ocean Drilling Program (ODP) during the drilling campaign Leg 160 in 1995. These wells transect the Eratosthenes Seamount, a drowned bathymetric high, and recovered a thick sequence of both pre- and post-Messinian sedimentary rocks, containing mainly marine marls and shales. In this study, 122 core samples of Late Cretaceous to Messinian age were analyzed in order to identify organic-matter-rich intervals and to determine their depositional environment as well as their source rock potential and thermal maturity. Both Total Organic and Inorganic Carbon (TOC, TIC) analyses as well as Rock-Eval pyrolysis were firstly performed for the complete set of samples whereas Total Sulfur (TS) analysis was only carried out on samples containing significant amount of organic matter (>0.3 wt.% TOC). Based on the Rock-Eval results, eight samples were selected for organic petrographic investigations and twelve samples for analysis of major aliphatic hydrocarbon compounds. The organic content is highly variable in the analyzed samples (0–9.3 wt.%). TS/TOC as well as several biomarker ratios (e.g. Pr/Ph < 2) indicate a deposition under dysoxic conditions for the organic matter-rich sections, which were probably reached during sporadically active upwelling periods. Results prove potential oil prone Type II kerogen source rock intervals of fair to very good quality being present in Turonian to Coniacian (average: TOC = 0.93 wt.%, HI = 319 mg HC/g TOC) and in Bartonian to Priabonian (average: TOC = 4.8 wt.%, HI = 469 mg HC/g TOC) intervals. A precise determination of the actual source rock thickness is prevented by low core recovery rates for the respective intervals. All analyzed samples are immature to early mature. However, the presence of deeper buried, thermally mature source rocks and hydrocarbon migration is indicated by the observation of solid bitumen impregnation in one Upper Cretaceous and in one Lower Eocene sample.

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 Organic geochemical and palynological studies of the Maastrichtian source rock intervals in Bida Basin, Nigeria: implications for hydrocarbon prospectivity

2020 ◽  
Vol 10 (8) ◽  
pp. 3191-3206
Author(s):  
Olusola J. Ojo ◽  
Ayoola Y. Jimoh ◽  
Juliet C. Umelo ◽  
Samuel O. Akande
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
High Yield ◽  
Thermal Maturity ◽  
Hydrocarbon Source Rock ◽  
Moderate Amount ◽  
Oxic Condition ◽  
Freshwater Swamp

Abstract The Patti Formation which consists of sandstone and shale offers the best potential source beds in the Bida Basin. This inland basin is one of the basins currently being tested for hydrocarbon prospectivity in Nigeria. Fresh samples of shale from Agbaja borehole, Ahoko quarry and Geheku road cut were analysed using organic geochemical and palynological techniques to unravel their age, paleoecology, palynofacies and source bed hydrocarbon potential. Palynological data suggest Maastrichtian age for the sediments based on the abundance of microfloral assemblage; Retidiporites magdalenensis, Echitriporites trianguliformis and Buttinia andreevi. Dinocysts belonging to the Spiniferites, Deflandrea and Dinogymnium genera from some of the analysed intervals are indicative of freshwater swamp and normal sea conditions. Palynological evidence further suggests mangrove paleovegetation and humid climate. Relatively high total organic carbon TOC (0.77–8.95 wt%) was obtained for the shales which implies substantial concentration of organic matter in the source beds. Hydrocarbon source rock potential ranges from 0.19 to 0.70 mgHC/g.rock except for a certain source rock interval in the Agbaja borehole with high yield of 25.18 mgHC/g.rock. This interval also presents exceptionally high HI of 274 mgHC/g.TOC and moderate amount of amorphous organic matter. The data suggests that in spite of the favourable organic matter quantity, the thermal maturity is low as indicated by vitrinite reflectance and Tmax (0.46 to 0.48 Ro% and 413 to 475 °C, respectively). The hydrocarbon extracts show abundance of odd number alkanes C27–C33, low sterane/hopane ratio and Pr/Ph > 2. We conclude that the source rocks were terrestrially derived under oxic condition and dominated by type III kerogen. Type II organic matter with oil and gas potential is a possibility in Agbaja area of Bida Basin. Thermal maturity is low and little, or no hydrocarbon has been generated from the source rocks.

Identification and Distribution of Lower Cretaceous Source Rocks in Ying’er Sag, Jiuquan Basin

2012 ◽  
Vol 616-618 ◽  
pp. 69-72
Author(s):  
Yi Bo Zhou ◽  
Guang Di Liu ◽  
Jia Yi Zhong
Keyword(s):  
Source Rock ◽  
Low Frequency ◽  
Sedimentary Facies ◽  
Organic Content ◽  
Source Rocks ◽  
Potential Source Rock ◽  
Wide Range ◽  
Strong Amplitude ◽  
System Tracts ◽  
High Organic Content

Based on the sequence stratigraphy study, the relation between dark mudstone ratio and sedimentary facies in different system tracts is observed and used to forcast the distribution of dark mudstones in the main formation combining with seismic data and well log. However, not all dark mudstones can generate hydrocarbon, so the source rock quality is quoted to calculate the thickness of the source rock within mudstone. The results show that the favored source rock in lake progressive system tracts and the bottom of highstand system tracts of Xiagou Formation and Chijinpu Formation are related to a group of reflectors with medium-strong amplitude, medium-low frequency and medium to comparatively good lateral continuity. The source rock of Xiagou Formation with high organic content and wide-range distribution is the major hydrocarbon source in Ying’er Sag, while Chijinpu Formation with thick dark mudstones is the potential source rock and the target of the further exploration.

scholarly journals Organic geochemical and petrographical characteristics of the major lower cretaceous petroleum source rock (Makhul Formation) in Kuwait - Arabian Gulf

2021 ◽  
Vol 49 (1) ◽  
Author(s):  
Fatma K. Bahman ◽  
◽  
Fowzia H. Abdullah ◽  
Abbas Saleh ◽  
Hossein Alimi ◽  
...  
Keyword(s):  
Organic Matter ◽  
Sea Level ◽  
Source Rock ◽  
Lower Cretaceous ◽  
Arabian Gulf ◽  
Carbon Isotope Ratio ◽  
Middle Part ◽  
Source Rocks ◽  
Peak Oil ◽  
Rock Composition

The Lower Cretaceous Makhul Formation is one of the major petroleum source rocks in Kuwait. This study aims to evaluate the Makhul source rock for its organic matter richness and its relation to the rock composition and depositional environment. A total of 117 core samples were collected from five wells in Raudhatain, Ritqa, Mutriba, Burgan, and Minagish oil fields north and south Kuwait. The rock petrographical studies were carried out using a transmitted and polarized microscope, as well as SEM and XRD analyses on selected samples. Total organic matter TOC and elemental analyses were done for kerogen type optically. The GC and GC-MS were done as well as the carbon isotope ratio. The results of this study show that at its earliest time the Makhul Formation was deposited in an anoxic shallow marine shelf environment. During deposition of the middle part, the water oxicity level was fluctuating from oxic to anoxic condition due to changes in sea level. At the end of Makhul and the start of the upper Minagish Formation, the sea level raised forming an oxic open marine ramp depositional condition. Organic geochemical results show that the average TOC of the Makhul Formation is 2.39% wt. High TOC values of 6.7% wt. were usually associated with the laminated mudstone intervals of the formation. The kerogen is of type II and is dominated by marine amorphous sapropelic organic matter with a mixture of zoo- and phytoplankton and rare terrestrial particles. Solvent extract results indicate non-waxy oils of Mesozoic origin that are associated with marine carbonate rocks. The formation is mature and at its peak oil generation in its deepest part in north Kuwait.

scholarly journals Timing of oil expulsion from source rocks and a revitalization of the pre-1970 model

2021 ◽  
Author(s):  
Per Arne Bjørkum
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Heavy Oil ◽  
Low Temperatures ◽  
Upper Jurassic ◽  
Hydrogen Gas ◽  
Source Rocks ◽  
Co2 Gas ◽  
Chemical Attributes ◽  
Oil Expulsion

New data from North Sea Upper Jurassic source rock samples show no decline in the total amount of organic matter (TOC) within the oil expulsion window between 120 and 150°C which is a key prediction by today’s model for oil expulsion. However, today’s model for oil expulsion is not consistent with either subsurface source rock TOC data or chemical attributes of shallow oils. Instead, these data are more consistent with oil expulsion occurring at much lower temperatures and shallower depths, more similar to models advocated by most oil explorers prior to 1970 where the oil was assumed to have expelled at burial depths less than ~2km. In this paper, main oil expulsion has been determined to be take place at burial depths less than 1km and approximately 30°C. The oil is mobilized by CO2 gas which is generated from decomposing organic matter and is predicted to migrate out of the source rock and into nearby high-permeable rocks via horizontal fractures that originate from loadbearing swelling organic lamina and in a direction towards decreasing overburden. The thermally immature (heavy) oil is then converted to light crude within the reservoir oil starting at 60-70°C by hydrogenation. Hydrogen gas is common in subsurface fluids and is provided to pooled oil from coalification of organic matter in mudstones. Thus, if the supply of hydrogen is limited, in-reservoir thermal upgrading will be hampered. In this model, most of the heavy oil accumulations encountered are immature rather than due to biodegradation of mature oil at low temperatures.

DEPOSITIONAL CONDITIONS OF THE NORTHERN ONSHORE PERTH BASIN (BASAL TRIASSIC)

2005 ◽  
Vol 45 (1) ◽  
pp. 262 ◽  
Author(s):  
K. Grice ◽  
R.E. Summons ◽  
E. Grosjean ◽  
R.J. Twitchett ◽  
W. Dunning ◽  
...  
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Source Rocks ◽  
Photic Zone ◽  
Diagenetic Alteration ◽  
Green Sulphur Bacteria ◽  
Sulphur Bacteria ◽  
Green Sulphur ◽  
Petroleum Source Rock ◽  
Lines Of Evidence

An oil-source rock correlation has been established for the northern onshore Perth Basin (Western Australia) based on unusual aromatic and polar biomarkers attributed ultimately to a green sulphur bacterial source. Several of these biomarkers have been identified throughout the entire Sapropelic Interval of a proven petroleum source rock intersected within a recently discovered marine Permian- Triassic Perth Basin borehole (Hovea–3) and several Perth Basin crude oils. Today, green sulphur bacteria live in the anaerobic zones of stratified lakes or in marine environments with restricted water circulation, where the upper sulphide limit coincides with the lower limit of oxygen. The presence of photosynthetic pigments and carotenoids of green sulphur bacteria, or their diagenetic alteration products in sediments provide unequivocal evidence for photic zone euxinic conditions in the paleowater column. Multiple lines of evidence for photic zone euxinia and euxinic depositional conditions for the Hovea–3 source rock have been obtained from biomarker analyses. Photic zone euxinia is usually associated with the widespread deposition of organic-matter-rich sediments that constitute important source rocks for petroleum deposits that are being exploited today. With the exception of the Perth Basin, such organic-matter-rich sediments are virtually absent from Upper Permian and Lower Triassic sediments globally. Several lines of evidence indicate localised surface ocean productivity may have played a key role in the deposition of a petroleum source rock at this location, although photic zone euxinia was globally more widespread during the Permian-Triassic Superanoxic Event.

EVIDENCE FOR A NEW OIL FAMILY IN THE NANCAR TROUGH AREA, TIMOR SEA

2002 ◽  
Vol 42 (1) ◽  
pp. 387 ◽  
Author(s):  
S.C. George ◽  
H. Volk ◽  
T.E. Ruble ◽  
M.P. Brincat
Keyword(s):  
Organic Matter ◽  
Fluid Inclusion ◽  
Source Rock ◽  
Bacterial Activity ◽  
Source Rocks ◽  
Drilling Mud ◽  
Terrestrial Organic Matter ◽  
High Contribution ◽  
Timor Sea ◽  
Oil Source

Geochemical evidence is presented for a previously unrecognised oil generative source rock in the Nancar Trough area. This source rock supplements the middle to late Jurassic source rocks, which have previously been shown to have generated most of the oils in the northern Bonaparte Basin and the Vulcan Sub-basin. Fluids with a strong contribution from this new source rock, defined here as the Nancar oil family, have an unusually high abundance of mid-chain substituted monomethylalkanes. In comparison, oils from the Vulcan Sub-basin contain mostly terminally substituted monomethylalkanes and the overall abundance is much lower. Oils from the Laminaria High and some from the northern Vulcan Sub-Basin show intermediate characteristics and may be co-sourced. Evidence from the analysis of fluid inclusion oils was important in establishing the presence of the new oil family because interference from drilling mud contaminants could be excluded. The detailed geochemistry of Ludmilla–1 fluid inclusion oil suggests the source rock for the Nancar oil family was deposited in a marine environment under sub-oxic conditions with limited sulphur content, a low contribution of terrestrial organic matter and a high contribution of organic matter from bacterial activity. Since monomethylalkanes are typical biomarkers of cyanobacteria, the source rock that gave rise to the new oil family may be rich in cyanobacterial organic matter. Further studies on sediment extracts are needed to establish an explicit oil-source rock correlation and to identify the stratigraphic location/palaeo-environment of the source rock. Such information will be valuable in determining the prospectivity of the large and relatively unexplored province draining the Nancar Trough kitchen.

AN EARLY CRETACEOUS SOURCE ROCK IN THE KENDREW TERRACE, DAMPIER SUB-BASIN?

1996 ◽  
Vol 36 (1) ◽  
pp. 477 ◽  
Author(s):  
S. Ryan-Grigor ◽  
C. M. Griffiths
Keyword(s):  
Source Rock ◽  
North Sea ◽  
Early Cretaceous ◽  
Late Jurassic ◽  
Large Scale ◽  
Free Water ◽  
Organic Content ◽  
Source Rocks ◽  
The North ◽  
Northern North Sea

The Early to Middle Cretaceous is characterised worldwide by widespread distribution of dark shales with high gamma ray readings and high organic contents defined as dark coloured mudrocks having the sedimentary, palaeoecological and geochemical characteristics associated with deposition under oxygen-deficient or oxygen-free bottom waters. Factors that contributed to the formation of the Early to Middle Cretaceous 'hot shales' are: rising sea-level, a warm equable climate which promoted water stratification, and large scale palaeogeographic features that restrict free water mixing. In the northern North Sea, the main source rock is the Late Jurassic to Early Cretaceous Kimmeridge Clay/Draupne Formation 'hot shale' which occurs within the Viking Graben, a large fault-bounded graben, in a marine environment with restricted bottom circulation and often anaerobic conditions. Opening of the basin during a major trans-gressive event resulted in flushing, and deposition of normal open marine shales above the 'hot shales'. The Late Callovian to Berriasian sediments in the Dampier Sub-basin are considered to have been deposited in restricted marine conditions below a stratified water column, in a deep narrow bay. Late Jurassic to Early Cretaceous marine sequences that have been cored on the North West Shelf are generally of moderate quality, compared to the high quality source rocks of the northern North Sea, but it should be noted that the cores are from wells on structural highs. The 'hot shales' are not very organic-rich in the northern Dampier Sub-basin and are not yet within the oil window, however seismic data show a possible reduction in velocity to the southwest in the Kendrew Terrace, suggesting that further south in the basin the shales may be within the oil window and may also be richer in organic content. In this case, they may be productive source rocks, analogous to the main source rock of the North Sea.

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