scholarly journals Hydrocarbon source rock potential of Miocene diatomaceous sequences in Szurdokpüspöki (Hungary) and Parisdorf/Limberg (Austria)

2020 ◽  
Vol 113 (1) ◽  
pp. 24-42
Author(s):  
Emilia Tulan ◽  
Michaela S. Radl ◽  
Reinhard F. Sachsenhofer ◽  
Gabor Tari ◽  
Jakub Witkowski
Keyword(s):  
Source Rock ◽  
Pannonian Basin ◽  
High Energy ◽  
Depositional Environments ◽  
Source Rocks ◽  
Hydrocarbon Source Rock ◽  
Petroleum Potential ◽  
Northern Margin ◽  
Geochemical Parameters ◽  
Study Sites

AbstractDiatomaceous sediments are often prolific hydrocarbon source rocks. In the Paratethys area, diatomaceous rocks are widespread in the Oligo-Miocene strata. Diatomites from three locations, Szurdokpüspöki (Hungary) and Limberg and Parisdorf (Austria), were selected for this study, together with core materials from rocks underlying diatomites in the Limberg area. Bulk geochemical parameters (total organic carbon [TOC], carbonate and sulphur contents and hydrogen index [HI]) were determined for a total of 44 samples in order to study their petroleum potential. Additionally, 24 samples were prepared to investigate diatom assemblages.The middle Miocene diatomite from Szurdokpüspöki (Pannonian Basin) formed in a restricted basin near a volcanic silica source. The diatom-rich succession is separated by a rhyolitic tuff into a lower non-marine and an upper marine layer. An approximately 12-m thick interval in the lower part has been investigated. It contains carbonate-rich diatomaceous rocks with a fair to good oil potential (average TOC: 1.28% wt.; HI: 178 to 723 mg HC/g TOC) in its lower part and carbonate-free sediments without oil potential in its upper part (average TOC: 0.14% wt.). The composition of the well-preserved diatom flora supports a near-shore brackish environment. The studied succession is thermally immature. If mature, the carbonate-rich part of the succession may generate about 0.25 tons of hydrocarbons per square meter. The diatomaceous Limberg Member of the lower Miocene Zellerndorf Formation reflects upwelling along the northern margin of the Alpine-Carpathian Foreland. TOC contents are very low (average TOC: 0.13% wt.) and demonstrate that the Limberg Member is a very poor source rock. The same is true for the underlying and over-lying rocks of the Zellerndorf Formation (average TOC: 0.78% wt.). Diatom preservation was found to differ considerably between the study sites. The Szurdokpüspöki section is characterised by excellent diatom preservation, while the diatom valves from Parisdorf/Limberg are highly broken. One reason for this contrast could be the different depositional environments. Volcanic input is also likely to have contributed to the excellent diatom preservation in Szurdokpüspöki. In contrast, high-energy upwelling currents and wave action may have contributed to the poor diatom preservation in Parisdorf. The hydrocarbon potential of diatomaceous rocks of Oligocene (Chert Member; Western Carpathians) and Miocene ages (Groisenbach Member, Aflenz Basin; Kozakhurian sediments, Kaliakra canyon of the western Black Sea) has been studied previously. The comparison shows that diatomaceous rocks deposited in similar depositional settings may hold largely varying petroleum potential and that the petroleum potential is mainly controlled by local factors. For example, both the Kozakhurian sediments and the Limberg Member accumulated in upwelling environments but differ greatly in source rock potential. Moreover, the petroleum potential of the Szurdokpüspöki diatomite, the Chert Member and the Groisenbach Member differs greatly, although all units are deposited in silled basins.

scholarly journals Source Rock Characterization of Silurian Tanezzuft and Devonian Awaynat Wanin Formations the Northern Edge of the Murzuq Basin, South West Libya

2020 ◽  
Vol 4 (1) ◽  
pp. 1-13
Author(s):  
Aboglila S
Keyword(s):  
Organic Matter ◽  
Source Rock ◽  
Depositional Environments ◽  
Source Rocks ◽  
Thermal Maturity ◽  
Maturity Level ◽  
Geochemical Parameters ◽  
Northern Edge ◽  
Rock Characterization ◽  
Tanezzuft Formation

Drill cutting samples (n = 92) from the Devonian Awaynat Wanin Formation and Silurian Tanezzuft Formation, sampled from three wells F1, G1 and H1, locate in the northern edge of the Murzuq basin (approximately 700 kilometers south of Tripoli). The studied samples were analyzed in the objective of their organic geochemical assessment such as the type of organic matter, depositional conditions and thermal maturity level. A bulk geochemical parameters and precise biomarkers were estimated, using chromatography-mass spectrometry (GC-MS) to reveal a diversity of their geochemical characterizations. The rock formations are having varied organic matter contents, ranged from fair to excellent. The total organic carbon (TOC) reached about 9.1 wt%, ranging from 0.6 to 2.93 wt% (Awaynat Wanin), 0.5 to 2.54 wt% (Tanezzuft) and 0.52 to 9.1 wt% (Hot Shale). The cutting samples are ranged oil-prone organic matter (OM) of hydrogen index (HI) ranged between 98 –396 mg HC/g TOC, related kerogen types are type II and II/III, with oxygen index (OI): 6 - 190 with one sample have value of 366 mg CO2/g. Thermal maturity of these source rocks is different, ranging from immature to mature and oil window in the most of Tanezzuft Formation and Hot Shale samples, as reflected from the production index data (PI: 0.08 - 034). Tmax and vitrinite reflectance Ro% data (Tmax: 435 – 454 & Ro%: 0.46 - 1.38) for the Awaynat Wanin. Biomarker ratios of specific hydrocarbons extracted from represented samples (n = 9), were moreover used to study thermal maturity level and depositional environments. Pristine/Phytane (Pr/Ph) ratios of 1.65 - 2.23 indicated anoxic to suboxic conditions of depositional marine shale and lacustrine source rock.

Triassic Hydrocarbon System of the Middle-Caspian Oil and Gas Basin

2021 ◽  
Author(s):  
Denis Sokolov ◽  
Mikhail Delengov ◽  
Regina Sabirianova ◽  
Konstantin Musikhin ◽  
Oleg Bogdanov
Keyword(s):  
Organic Carbon ◽  
Source Rock ◽  
Oil And Gas ◽  
Source Rocks ◽  
Research Approach ◽  
Basin Modeling ◽  
Petroleum Potential ◽  
Hydrocarbon System ◽  
Geochemical Parameters ◽  
Wide Range

Abstract The objective of this paper is to assess the generation potential of the Triassic hydrocarbon (HC) source rocks for the petroleum potential of the Middle-Caspian Oil and Gas Basin. Tectonically the study area belongs to the Epigercine Scythian-Turanian plate, which includes the following major tectonic elements: the Karpinsk-Mangyshlak ridge and the Prikum-Central Caspian system of troughs and uplifts. Comprehensive research approach to identify the main features of the Triassic hydrocarbon system, such as the interpretation of seismic data, laboratory geochemical analysis and evolution restoration of the hydrocarbon systems elements by 3D basin modeling techniques. The geochemical research includes pyrolytic analysis of potential Triassic source rocks, determination of the vitrinite reflectance values, chromatography-Mass Spectrometry studies of molecular structure. The subsequent basin modeling made it possible to integrate a wide range of geological and geophysical information into a single complex. These basin modeling results provide a better understanding of evolution restoration of the hydrocarbon systems elements and make it possible to foresee hydrocarbon accumulation's localization. The combined set of research helped to identify the boundaries of the Triassic HC source rocks in the Middle-Caspian Basin. It also allowed characterizing in detail their geochemical parameters and evaluating the volume of its generation potential. Triassic deposits are part of the taphrogenic intermediate complex of the Scythian platform and mainly located in graben structures. The increased content of organic matter is associated with the Lower Triassic Neftekum Formation of the Olenek Stage, which is composed of clayey limestones and mudstones. The content of total organic carbon (TOC) in limestones in the Eastern Fore-Caucasus area averages 0.1 % in some layers up to 2.05 %. The average TOC content in mudstones is 0.43 %. This parameter is up to 0.9 % in the direction of the East-Manych trough. Triassic deposits were penetrated by 5 wells, the average content of organic carbon was 1.22% in mudstones. The samples show a migrant presence of bitumen. According to 3D basin modeling results, the Olenek HC source rock has practically exhausted its potential in on most of the except the southern part of the study area, as well as the eastern flank. The Olenek stage's Neftekum HC source rock in the southern part of the model is identified with MK1-3 catagenesis gradations, this grade represents the main zone of oil generation. At the northern part of study area, those strata of source rock are positioned at a great depth. The hydrocarbon source rock in those areas have reached the grades of catagenesis MK5-AK1, which represents the zones of condensate and gas formation. The research results allow to take a new look at the influence of the Triassic hydrocarbon system and its prospects of petroleum potential of the Middle-Caspian Oil and Gas Basin. It also allows evaluating the generation parameters variance of the Olenek stage's Neftekum HC source rock regarding its area and time period.

scholarly journals Search for source rocks of the crude oils of the Drmno depression, southern part of the Pannonian Basin, Serbia

2002 ◽  
Vol 67 (8-9) ◽  
pp. 553-566 ◽  
Author(s):  
Branimir Jovancicevic ◽  
H. Wehner ◽  
G. Scheeder ◽  
K. Stojanovic ◽  
Aleksandar Sainovic ◽  
...  
Keyword(s):  
Source Rock ◽  
Pannonian Basin ◽  
Source Rocks ◽  
Crude Oils ◽  
Geological Interpretation ◽  
Geochemical Parameters ◽  
Sedimentary Core ◽  
Oil Source ◽  
Gas Fields ◽  
First Time

In a search for source rocks of the crude oils of the Drmno depression (southern part of the Pannonian Basin, Serbia), based on bulk and specific organic geochemical parameters, six out of eight Sirakovo, Bubu{inac and Bradarac sedimentary core samples were found to possess typical source rock characteristics. By comparing the results observed for these sedimentary samples with the corresponding properties of the crude oils from the Sirakovo and Bradarac oil-gas fields, a positive organic geochemical oil-source rock correlation was experienced for the first time within this basin. This finding may be considered as an important step towards the ultimate organic geochemical/geological interpretation of the Drmno depression.

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 The Cambrian Henson Gletscher Formation: a mature to postmature hydrocarbon source rock sequence from North Greenland

1987 ◽  
Vol 133 ◽  
pp. 141-157
Author(s):  
F.G Christiansen ◽  
H Nøhr-Hansen ◽  
O Nykjær
Keyword(s):  
Source Rock ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Reservoir Rocks ◽  
Potential Source ◽  
Potential Reservoir ◽  
Field Season ◽  
North Greenland

During the 1985 field season the Cambrian Henson Gletscher Formation in central North Greenland was studied in detail with the aim of evaluating its potential as a hydrocarbon source rock. The formation contains organic rich shale and carbonate mudstone which are considered to be potential source rocks. These are sedimentologically coupled with a sequence of sandstones and coarse carbonates which might be potential reservoir rocks or migration conduits. Most of the rocks exposed on the surface are, however, thermally mature to postrnature with respect to hydrocarbon generation, leaving only few chances of finding trapped oil in the subsurface of the area studied in detail.

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.

Petrography and geochemistry of the siliciclastic Araba Formation (Cambrian), east Sinai, Egypt: implications for provenance, tectonic setting and source weathering

2015 ◽  
Vol 154 (1) ◽  
pp. 1-23 ◽  
Author(s):  
HOSSAM A. TAWFIK ◽  
IBRAHIM M. GHANDOUR ◽  
WATARU MAEJIMA ◽  
JOHN S. ARMSTRONG-ALTRIN ◽  
ABDEL-MONEM T. ABDEL-HAMEED
Keyword(s):  
Tectonic Setting ◽  
Source Area ◽  
Xrd Analysis ◽  
Climatic Conditions ◽  
Source Rocks ◽  
Northern Margin ◽  
Rock Fragments ◽  
Geochemical Parameters ◽  
Clastic Sediments ◽  
Chemical Index

AbstractCombined petrographic and geochemical methods are utilized to investigate the provenance, tectonic setting, palaeo-weathering and climatic conditions of the Cambrian Araba clastic sediments of NE Egypt. The ~ 60 m thick Araba Formation consists predominantly of sandstone and mudstone interbedded with conglomerate. Petrographically the Araba sandstones are mostly sub-mature and classified as subarkoses with an average framework composition of Q80F14L6. The framework components are dominated by monocrystalline quartz with subordinate K-feldspar, together with volcanic and granitic rock fragments. XRD analysis demonstrated that clay minerals comprise mixed-layer illite/smectite (I/S), illite and smectite, with minor kaolinite. Diagenetic features of the sandstone include mechanical infiltration of clay, mechanical and chemical compaction, cementation, dissolution and replacement of feldspars by carbonate cements and clays. The modal composition and geochemical parameters (e.g. Cr/V, Y/Ni, Th/Co and Cr/Th ratios) of the sandstones and mudstones indicate that they were derived from felsic source rocks, probably from the crystalline basement of the northern fringe of the Arabian–Nubian Shield. The study reveals a collisional tectonic setting for the sediments of the Araba Formation. Palaeo-weathering indices such as the chemical index of alteration (CIA), chemical index of weathering (CIW) and plagioclase index of alteration (PIA) of the clastic sediments suggest that the source area was moderately chemically weathered. On the northern margin of Gondwana, early Palaeozoic weathering occurred under fluctuating climatic conditions.

PETROLEUM POTENTIAL OF THE NEOPROTEROZOIC WESTERN OFFICER BASIN, WESTERN AUSTRALIA, BASED ON A SOURCE ROCK MODEL FROM EMPRESS-IA

1999 ◽  
Vol 39 (1) ◽  
pp. 322 ◽  
Author(s):  
G.M. Carlsen ◽  
S.N. Apak ◽  
K.A.R. Ghori K. Grey ◽  
M.K. Stevens
Keyword(s):  
Organic Matter ◽  
Western Australia ◽  
Depositional Environments ◽  
Source Rocks ◽  
Petroleum Potential ◽  
Organic Facies ◽  
Organic Growth ◽  
Rock Model ◽  
Depositional Controls ◽  
The Impact

The sedimentology, palaeontology and geochemistry of Neoproterozoic, organic-rich, clastic and related carbonate deposits in Western Australia provide new insights into the first-order depositional controls on hydrocarbon source rocks in the Neoproterozoic. Organic facies are correlated with depositional facies, revealing the impact of organic productivity and transport of organic rich sediments on the accumulation of organic matter in different depositional environments. Sedimentation is largely limited to ramp, platform, shoal, lagoon and sabkha environments.Growth of benthic organisms in the photic zone was the primary process controlling the production of organic matter in the ramp-shoreline system of the Kanpa Formation. Storms and floods were the primary mechanism for moving organic rich sediments into dysoxic and anoxic depositional environments. Variations in organic facies are indicated by: 1) changes in the palynomorph assemblages, particularly the increase in acritarchs within shallow-water ramp facies and cyanobacterial filaments in quiet-water sediments; 2) organic-rich laminae, containing abundant cyanobacterial filaments and mat material; and 3) the oxidation state of preserved organic remains.Periods of high organic growth rates or periods of mass mortality may have led to the development of an anoxic zone at the water-sediment interface. In the shoal and lagoonal settings, higher rates of clastic sediment dilution combined with oxygenated conditions resulted in lower TOC and hydrogen depleted organic facies.Condensed sections overlying stromatolitic dolomites represent the most effective organic facies of all of the potential source laminae sampled in Empress–IA. Most of the Officer Basin succession is currently within the oil-generating window and hydrocarbon shows encourage further exploration.

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.

scholarly journals Oil chemometrics and geochemical correlation in the Weixinan Sag, Beibuwan Basin, South China Sea

2020 ◽  
Vol 38 (6) ◽  
pp. 2695-2710
Author(s):  
Yao-Ping Wang ◽  
Xin Zhan ◽  
Tao Luo ◽  
Yuan Gao ◽  
Jia Xia ◽  
...  
Keyword(s):  
Source Rock ◽  
Principal Component ◽  
Sedimentary Basins ◽  
Oil Field ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Crude Oils ◽  
Geochemical Parameters ◽  
Group I ◽  
Oil Source

The oil–oil and oil–source rock correlations, also termed as geochemical correlations, play an essential role in the construction of petroleum systems, guidance of petroleum exploration, and definition of reservoir compartments. In this study, the problems arising from oil–oil and oil–source rock correlations were investigated using chemometric methods on oil and source rock samples from the WZ12 oil field in the Weixinan sag in the Beibuwan Basin. Crude oil from the WZ12 oil field can be classified into two genetic families: group A and B, using multidimensional scaling and principal component analysis. Similarly, source rocks of the Liushagang Formation, including its first, second, and third members, can be classified into group I and II, corresponding to group B and A crude oils, respectively. The principle geochemical parameters in the geochemical correlation for the characterisation and classification of crude oils and source rocks were 4MSI, C27Dia/C27S, and C24 Tet/C26 TT. This study provides insights into the selection of appropriate geochemical parameters for oil–oil and oil–source rock correlations, which can also be applied to other sedimentary basins.

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