scholarly journals Burial and Thermal History Modeling of the Paleozoic–Mesozoic Basement in the Northern Margin of the Western Outer Carpathians (Case Study from Pilzno-40 Well, Southern Poland)

Minerals ◽  
2021 ◽  
Vol 11 (7) ◽  
pp. 733
Author(s):  
Dariusz Botor
Keyword(s):  
Heat Flow ◽  
Thermal History ◽  
Middle Jurassic ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Northern Margin ◽  
Outer Carpathians

Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields.

scholarly journals Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)

2012 ◽  
Vol 63 (4) ◽  
pp. 335-342 ◽  
Author(s):  
Paweł Kosakowski ◽  
Magdalena Wróbel
Keyword(s):  
Organic Matter ◽  
Thermal History ◽  
Vitrinite Reflectance ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Burial History ◽  
Se Poland ◽  
Carpathian Foredeep ◽  
Outer Carpathians

Burial history, thermal history and hydrocarbon generation modelling of the Jurassic source rocks in the basement of the Polish Carpathian Foredeep and Outer Carpathians (SE Poland)Burial history, thermal maturity, and timing of hydrocarbon generation were modelled for the Jurassic source rocks in the basement of the Carpathian Foredeep and marginal part of the Outer Carpathians. The area of investigation was bounded to the west by Kraków, to the east by Rzeszów. The modelling was carried out in profiles of wells: Będzienica 2, Dębica 10K, Góra Ropczycka 1K, Goleszów 5, Nawsie 1, Pławowice E1 and Pilzno 40. The organic matter, containing gas-prone Type III kerogen with an admixture of Type II kerogen, is immature or at most, early mature to 0.7 % in the vitrinite reflectance scale. The highest thermal maturity is recorded in the south-eastern part of the study area, where the Jurassic strata are buried deeper. The thermal modelling showed that the obtained organic matter maturity in the initial phase of the "oil window" is connected with the stage of the Carpathian overthrusting. The numerical modelling indicated that the onset of hydrocarbon generation from the Middle Jurassic source rocks was also connected with the Carpathian thrust belt. The peak of hydrocarbon generation took place in the orogenic stage of the overthrusting. The amount of generated hydrocarbons is generally small, which is a consequence of the low maturity and low transformation degree of kerogen. The generated hydrocarbons were not expelled from their source rock. An analysis of maturity distribution and transformation degree of the Jurassic organic matter shows that the best conditions for hydrocarbon generation occurred most probably in areas deeply buried under the Outer Carpathians. It is most probable that the "generation kitchen" should be searched for there.

scholarly journals Source rocks evaluation of the Paleogene Shahejie 3 Formation in the Dongpu Depression, Bohai Bay Basin

2018 ◽  
Vol 37 (1) ◽  
pp. 394-411 ◽  
Author(s):  
Zi-Ran Jiang ◽  
Yin-Hui Zuo ◽  
Mei-Hua Yang ◽  
Yun-Xian Zhang ◽  
Yong-Shui Zhou
Keyword(s):  
Thermal History ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Geochemical Data ◽  
Bohai Bay ◽  
Type I ◽  
Hydrocarbon Generation ◽  
Thermal Maturity ◽  
Dongpu Depression ◽  
Two Stages

Present simulation results based on two-dimensional basin cannot obtain accurate evaluations of petroleum resources because of not combining the thermal history in the Dongpu Depression. In this paper, Shahejie 3 Formation source rocks are evaluated using the geochemical data, and based on the thermal history, the thermal maturity evolution of typical wells and the top and bottom of the Shahejie 3 Formation source rocks are modeled using BasinMod software. Results show that source rocks are mainly distributed in the Haitongji-Liutun and Qianliyuan areas, and dominated by medium to high maturity source rocks. Organic matter types are primarily types II and III kerogen with a small amount of type I. The Shahejie 3 Formation source rocks in the Menggangji area experienced two stages of hydrocarbon generation: (1) during the Dongying Formation depositional period (33–17 Ma) and (2) from the Minghuazhen Formation depositional period to present (5.1–0 Ma). The source rocks are generally underdeveloped with low potential for hydrocarbon generation due to nonpoor and thin source rocks in this area. The two stages of hydrocarbon generation are not obvious for other areas. When the bottom of the source rocks reached overmature stage, the mid-lower Shahejie 3 Formation experienced the peak of hydrocarbon generation during the Dongying Formation depositional period. The thermal maturity evolution of the Shahejie 3 Formation source rocks revealed that the main hydrocarbon generation period was during the Dongying Formation depositional period. Therefore, petroleum exploration is suggested to be performed at the Shahejie 3 Formation source rocks in the Qianliyuan and Haitongji-Liutun areas to study the lithology and discover complex petroleum reservoirs in the Dongpu Depression.

scholarly journals Thermal and maturation history for Carboniferous source rocks in the Junggar Basin, Northwest China: implications for hydrocarbon exploration

2020 ◽  
Vol 17 (1) ◽  
pp. 36-50 ◽  
Author(s):  
Di Hu ◽  
Song Rao ◽  
Zhu-Ting Wang ◽  
Sheng-Biao Hu
Keyword(s):  
Heat Flow ◽  
Thermal History ◽  
Thermal State ◽  
Junggar Basin ◽  
Hydrocarbon Exploration ◽  
Source Rocks ◽  
Hydrocarbon Generation ◽  
Early Maturation ◽  
Hydrocarbon Maturation ◽  
History Of

AbstractThe reconstruction of thermal history is an important component of basin evolution and hydrocarbon exploration. Based on vitrinite reflectance data, we integrate the paleo-temperature gradient and paleo-heat flow methods to reconstruct the thermal history of Junggar Basin. Compared with present thermal state, the Junggar Basin experienced much a higher heat flow of ca. 80–120 mW/m2 during the Carboniferous. This feature can be attributed to large-scale volcanic events and related thermal effects. The hydrocarbon maturation history of Carboniferous source rocks indicates that the temperature rapidly reached the threshold of hydrocarbon generation during the Late Carboniferous and has never achieved such a high level since then. This characteristic resulted in the early maturation of hydrocarbons in Carboniferous source rocks. Meanwhile, the results reveal that hydrocarbon maturities are different among various tectonic units in Junggar Basin. The kerogen either rapidly broke through the dry gas period so that cracking of gas occurred or remained in the oil maturation window forming oil reservoirs, which depended on the tectonic background and depositional environment. In this study, we present the thermal and hydrocarbon maturation history since the Carboniferous, which has important implications for further hydrocarbon exploration in Junggar Basin.

scholarly journals Thermal maturity of the Upper Triassic–Middle Jurassic Shemshak Group (Alborz Range, Northern Iran) based on organic petrography, geochemistry and basin modelling: implications for source rock evaluation and petroleum exploration

2011 ◽  
Vol 149 (1) ◽  
pp. 19-38 ◽  
Author(s):  
ALI SHEKARIFARD ◽  
FRANÇOIS BAUDIN ◽  
KAZEM SEYED-EMAMI ◽  
JOHANN SCHNYDER ◽  
FATIMA LAGGOUN-DEFARGE ◽  
...  
Keyword(s):  
Middle Jurassic ◽  
Vitrinite Reflectance ◽  
Upper Triassic ◽  
Petroleum Exploration ◽  
Thermal Maturity ◽  
Northern Iran ◽  
Carbonaceous Shales ◽  
Petroleum Generation ◽  
Central Eastern ◽  
Alborz Range

AbstractOrganic petrography and geochemical analyses have been carried out on shales, carbonaceous shales and coals of the Shemshak Group (Upper Triassic–Middle Jurassic) from 15 localities along the Alborz Range of Northern Iran. Thermal maturity of organic matter (OM) has been investigated using vitrinite reflectance, Rock-Eval pyrolysis and elemental analysis of kerogen. Reflectance of autochthonous vitrinite varies from 0.6 to 2.2% indicating thermally early-mature to over-mature OM in the Shemshak Group, in agreement with other maturity parameters used. The shales of the Shemshak Group are characterized by poor to high residual organic carbon contents (0.13 to 5.84%) and the presence of hydrogen-depleted OM, predominantly as a consequence of oxidation of OM at the time of deposition and the hydrogen loss during petroleum generation. According to light-reflected microscopy results, vitrinite/vitrinite-like macerals are dominant in the kerogen concentrates from the shaly facies. The coals and carbonaceous shales of the Shemshak Group show a wide range in organic carbon concentration (3.5 to 88.6%) and composition (inertinite- and vitrinite-rich types), and thereby different petroleum potentials. Thermal modelling results suggest that low to moderate palaeo-heat flow, ranging from 47 to 79 mW m−2 (57 mW m−2 on average), affected the Central-Eastern Alborz basin during Tertiary time, the time of maximum burial of the Shemshak Group. The maximum temperature that induced OM maturation of the Shemshak Group seems to be related to its deep burial rather than to a very strong heat flow related to an uppermost Triassic–Liassic rifting. The interval of petroleum generation in the most deeply buried part of the Shemshak Group (i.e. Tazareh section) corresponds to Middle Jurassic–Early Cretaceous times. Exhumation of the Alborz Range during Late Neogene time, especially along the axis of the Central-Eastern Alborz, where maximum vitrinite reflectance values are recorded, probably destroyed possible petroleum accumulations. However, on the northern flank of the Central-Eastern Alborz, preservation of petroleum accumulations may be expected. The northern part of the basin therefore seems the best target for petroleum exploration.

scholarly journals Burial and thermal history simulation of the subsurface Paleozoic source rocks in Faghur basin, north Western Desert, Egypt: Implication for hydrocarbon generation and expulsion history

2019 ◽  
Vol 28 (3) ◽  
pp. 261-271 ◽  
Author(s):  
Esam A. Abd El Gawad ◽  
Mohamed F. Ghanem ◽  
Mostafa M. Lotfy ◽  
Doaa A. Mousa ◽  
Mostafa G. Temraz ◽  
...  
Keyword(s):  
Thermal History ◽  
Source Rocks ◽  
Western Desert ◽  
Hydrocarbon Generation ◽  
North Western

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.

PETROLEUM SYSTEMS IN TASMANIA'S FRONTIER ONSHORE BASINS

2000 ◽  
Vol 40 (1) ◽  
pp. 26
Author(s):  
M.R. Bendall C.F. Burrett ◽  
H.J. Askin
Keyword(s):  
Oil And Gas ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Late Triassic ◽  
Upper Permian ◽  
Lower Permian ◽  
Peak Oil ◽  
Petroleum Systems ◽  
Upper Proterozoic ◽  
Oil Seep

Sedimentary successions belonging to three petroleum su persy stems can be recognised in and below the Late Carboniferous to Late Triassic onshore Tasmania Basin. These are the Centralian, Larapintine and Gondwanan. The oldest (Centralian) is poorly known and contains possible mature source rocks in Upper Proterozoic dolomites. The Larapintine 2 system is represented by rocks of the Devonian fold and thrust belt beneath the Tasmania Basin. Potential source rocks are micrites and shales within the 1.8 km-thick tropical Ordovician Gordon Group carbonates. Conodont CAI plots show that the Gordon Group lies in the oil and gas windows over most of central Tasmania and probably under much of the Tasmania Basin. Potential reservoirs are the upper reefal parts of the Gordon Group, paleokarsted surfaces within the Gordon Group and the overlying sandstones of the Siluro-Devonian Tiger Range and Eldon Groups. Seal rocks include shales within the Siluro-Devonian and Upper Carboniferous-Permian tillites and shales.The Gondwanan supersystem is the most promising supersystem for petroleum exploration within the onshore Tasmania Basin. It is divided into two petroleum systems— the Early Permian Gondwanan 1 system, and the Late Permian to Triassic Gondwanan 2 system. Excellent source rocks occur in the marine Tasmanite Oil Shale and other sections within the Lower Permian Woody Island and Quamby Formations of the Gondwanan 1 system and within coals and freshwater oil shales of the Gondwanan 2 system. These sources are within the oil and gas windows across most of the basin and probably reached peak oil generation at about 100 Ma. An oil seep, sourced from a Tasmanites-rich, anoxic shale, is found within Jurassic dolerite 40 km WSW of Hobart. Potential Gondwanan 1 reservoirs are the glaciofluvial Faulkner Group sandstones and sandstones and limestones within the overlying parts of the glaciomarine Permian sequence. The Upper Permian Ferntree Mudstone Formation provides an effective regional seal. Potential Gondwanan 2 reservoirs are the sandstones of the Upper Permian to Norian Upper Parmeener Supergroup. Traps consisting of domes, anticlines and faults were formed probably during the Early Cretaceous. Preliminary interpretation of a short AGSO seismic profile in the Tasmania Basin shows that, contrary to earlier belief, structures can be mapped beneath extensive and thick (300 m) sills of Jurassic dolerite. In addition, the total section of Gondwana to Upper Proterozoic to Triassic sediments appears to be in excess of 8,500 m. These recent studies, analysis of the oil seep and drilling results show that the Tasmanian source rocks have generated both oil and gas. The Tasmania Basin is considered prospective for both petroleum and helium and is comparable in size and stratigraphy to other glaciomarine-terrestrial Gondwanan basins such as the South Oman and Cooper Basins.

The transformation effect of source rock-derived acidic fluid on carbonate reservoir from simulation experiments

2020 ◽  
Author(s):  
Qian Ding ◽  
Zhiliang He ◽  
Dongya Zhu
Keyword(s):  
Physical Properties ◽  
Source Rock ◽  
Carbonate Reservoir ◽  
Carbonate Reservoirs ◽  
Source Rocks ◽  
Petroleum Exploration ◽  
Hydrocarbon Generation ◽  
High Quality ◽  
Simulation Experiments ◽  
Deep Layers

<p>Deep and ultra-deep carbonate reservoir is an important area of petroleum exploration. However, the prerequisite for predicting high quality deep ultra-deep carbonate reservoirs lays on the mechanism of carbonate dissolution/precipitation. It is optimal to perform hydrocarbon generation-dissolution simulation experiments to clarify if burial dissolution could improve the physical properties of carbonate reservoirs, while quantitatively and qualitatively describe the co-evolution process of source rock and carbonate reservoirs in deep layers. In this study, a series of experiments were conducted with the limestone from the Ordovician Yingshan Formation in the Tarim Basin, and the low maturity source rock from Yunnan Luquan, with a self-designed hydrocarbon generation-dissolution simulation equipment. The controlling factors accounted for the alteration of carbonate reservoirs and dissolution modification process by hydrocarbon cracking fluid under deep burial environments were investigated by petrographic and geochemical analytical methods. In the meantime, the transformation mechanism of surrounding rocks in carbonate reservoirs during hydrocarbon generation process of source rock was explored. The results showed that: in the burial stage, organic acid, CO<sub>2</sub> and other acidic fluids associated with thermal evolution of deep source rocks could dissolve carbonate reservoirs, expand pore space, and improve porosity. Dissolution would decrease with the increasing burial depth. Whether the fluid could improve reservoir physical properties largely depends on calcium carbonate saturation, fluid velocity, water/rock ratio, original pore structure etc. This study could further contribute to the prediction of high-quality carbonate reservoirs in deep and ultra-deep layers.</p>

scholarly journals Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine)

2012 ◽  
Vol 63 (4) ◽  
pp. 319-333 ◽  
Author(s):  
Paweł Kosakowski ◽  
Dariusz Więcław ◽  
Adam Kowalski ◽  
Yuriy Koltun
Keyword(s):  
Organic Matter ◽  
Middle Jurassic ◽  
Sedimentary Cover ◽  
Source Rocks ◽  
Hydrocarbon Potential ◽  
Hydrocarbon Generation ◽  
Hydrocarbon Source Rock ◽  
Core Samples ◽  
Se Poland ◽  
Geochemical Parameters

Assessment of hydrocarbon potential of Jurassic and Cretaceous source rocks in the Tarnogród-Stryi area (SE Poland and W Ukraine) The Jurassic/Cretaceous stratigraphic complex forming a part of the sedimentary cover of both the eastern Małopolska Block and the adjacent Łysogóry-Radom Block in the Polish part as well as the Rava Rus'ka and the Kokhanivka Zones in the Ukrainian part of the basement of the Carpathian Foredeep were studied with geochemical methods in order to evaluate the possibility of hydrocarbon generation. In the Polish part of the study area, the Mesozoic strata were characterized on the basis of the analytical results of 121 core samples derived from 11 wells. The samples originated mostly from the Middle Jurassic and partly from the Lower/Upper Cretaceous strata. In the Ukrainian part of the study area the Mesozoic sequence was characterized by 348 core samples collected from 26 wells. The obtained geochemical results indicate that in both the south-eastern part of Poland and the western part of Ukraine the studied Jurassic/Cretaceous sedimentary complex reveals generally low hydrocarbon source-rock potential. The most favourable geochemical parameters: TOC up to 26 wt. % and genetic potential up to 39 mg/g of rock, were found in the Middle Jurassic strata. However, these high values are contradicted by the low hydrocarbon index (HI), usually below 100 mg HC/g TOC. Organic matter from the Middle Jurassic strata is of mixed type, dominated by gas-prone, Type III kerogen. In the Polish part of the study area, organic matter dispersed in these strata is generally immature (Tmax below 435 °C) whereas in the Ukrainian part maturity is sufficient for hydrocarbon generation.

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