Silurian Source Rocks Research Articles

تحليل السحنات الرسوبية وتوصيف الخزانات لتكوينات حواز والمومنيات من العصر الأوردوفيشي وتكوين عوينات وأنين من العصر الديفوني، منطقة 176-4، حوض مرزق، جنوب غرب ليبيا

The Ordovician to Devonian succession in the in Murzuq Basin represents the most important part of the lower Paleozoic terrigenous Al Gargaf siliciclastic group, which consists of several formations such as the Ordovician Hawaz, Melaz Shuqran and Mamuniyat Formations and the Devonian Tadrart and Awainat Wanin Formations. Different integrated methods were used and implemented in order to understand lithology and sedimentary structures of the Ordovician, Silurian and Devonian formations. Firstly, intensive geological field trips were carried out and special attention was focused on Ordovician and Devonian reservoir sandstones and the Silurian source rocks. Secondly facies analysis and sequence stratigraphy methods were applied to figure out a simple sequence stratigraphic division of the Ordovician to Devonian succession based on outcrop sections, well logs and interpreted seismic sections. As a result of the petrographic field investigation and facies analysis based on seismic interpretation of the several seismic lines in the study area. Sequence boundaries of the Ordovician and Devonian succession on all seismic sections were identified by using specific reflection terminations such as onlap and erosional truncations features. 13 seismic facies were recognized, divided and classified for each of the examined stratigraphic formations (4 facies in Hawaz, 5 facies in Melaz Shuqran and Mamuniyat formations and 4 facies in the Tadrart and Awainat Wanin). A seismic facies classification chart was made on the basis of the classified seismic facies scheme, since depositional systems and types of seismic facies differ in each stratigraphic succession. Depositional sequences of sedimentary environments were identified from well logs and available 2D seismic sections and sequence stratigraphic frameworks were constructed for the Ordovician and Devonian formations. Based on the facies analysis and sequence stratigraphy interpretations, two different order sequences in the Ordovician to Devonian succession have been found and identified: The major sequences are possibly 2nd-order sequences in time duration. They are clearly traceable on all seismic sections. May be minor sequences are possibly 3rd-order sequences, and they are not traceable on all seismic sections clearly, but are recognized on well logs or outcrop sections. Eventually, all obtained information and that results were plotted on the different maps for each examined section to construct a depositional model and to estimate the maximum distributions of each formation separately on the basis of depositional system interpretations. Keywords: Murzuq Basin, Al Gargaf siliciclastic group, Ordovician to Devonian succession, depositional system and seismic facies

PETROLEUM GEOLOGY OF THE CENOZOIC SUCCESSION IN THE ZAGROS OF SW IRAN: A SEQUENCE STRATIGRAPHIC APPROACH

The Cenozoic stratigraphy of the Zagros records the ongoing collision between the Arabian and Eurasian Plates and the closure of NeoTethys. A Paleogene NW‐SE trending foreland basin was inherited from a Late Cretaceous precursor. Widespread progradation into the foredeep was a feature of both margins which, allied to ongoing tectonism, had by the late Eocene led to the narrowing and subsequent division of the foredeep into the Lurestan – Khuzestan and Lengeh Troughs, separated by the northward continuation of the rejuvenated Qatar‐Fars Arch. This sub‐division strongly influenced subsequent deposition and the petroleum geology of the area. In addition, the diachronous nature of the Arabian – Eurasian collision led to strong diachroneity in lithostratigraphic units along the length of the Zagros. Hence its petroleum geology is best understood within a regional sequence stratigraphic framework. This study identifies three tectono‐megasequences (TMS 10, TMS 11a, TMS 11b) and multiple depositional sequences.The Cenozoic contains a world class hydrocarbon province with prolific oil reservoirs in the Oligo‐Miocene Asmari Formation sealed by the evaporite‐dominated Gachsaran Formation, mostly contained within giant NW‐SE trending “whaleback” anticlines concentrated in the Dezful Embayment. Reservoirs in the SW are dominantly siliciclastic or comprise mixed siliciclastics and carbonates, whereas those to the east and NE are dominated by fractured carbonates. There remains untested potential in stratigraphic traps, especially in deeperwater sandstone reservoirs deposited along the SW margin of the foredeep.Late Miocene to Pliocene charge to the Asmari reservoirs was mostly from Aptian – Albian Kazhdumi Formation source rocks. In some fields, an additional component was from organic‐rich late Eocene to earliest Oligocene Pabdeh Formation source rocks confined to the narrowing Lurestan – Khuzestan Trough. Where mature, the latter source rock is also a potential unconventional reservoir target, although the prospective area is limited due to recent uplift and erosion. Deeper Jurassic source rocks contributed to the Cheshmeh Khush field in Dezful North. Silurian source rocks charged gas‐bearing structures in the Bandar Abbas region.

Petroleum system of the fold-and-thrust belt of the United Arab Emirates: New insights based on 1D and 2D basin modeling

The hydrocarbon potential of the fold-and-thrust belt (FTB) in the United Arab Emirates (UAE)-Oman mountains has received limited attention to date, leading to a poor understanding of the petroleum systems in this region. Despite the existence of hydrocarbon fields within the FTB, the source rock potential has not been adequately studied. This study aims to address this knowledge gap using 1D and 2D basin modeling approaches to evaluate the petroleum system of the FTB. In addition, gas chromatographs are also used to correlate hydrocarbon occurrences with their source rock. This study's findings identify the Silurian, Upper Cretaceous, Paleocene–Eocene, and Oligocene formations as the primary source rocks in the study area. Silurian shales, encountered in a well in the northern UAE, are currently considered overmature. The Cenozoic source rocks exhibit a spectrum of Total Organic Carbon (TOC) content, ranging from less than 1 to as high as 2 wt%, leading to variable degrees of expulsion efficiency. The maturity of these rocks varies based on their position in relation to the FTB and foredeep, with increasing maturity towards the north. The Upper Cretaceous sequences display low TOC and Hydrogen Index, indicating very low expulsion efficiency. The present-day distribution of maturity is largely influenced by Late Cretaceous and Oligocene–Miocene compressional events that affected the northern and northeastern Arabian Plate. This analysis shows that hydrocarbon expulsion from the Silurian source rocks was initiated during the Middle-Late Jurassic. These hydrocarbons are presumed to have migrated through Upper Permian, Jurassic, and Lower and middle Cretaceous reservoirs. Westward hydrocarbon migration, towards a regional bulge, may have also occurred following compressional events that resulted in lithospheric flexure and formation of the foreland basin. Notably, certain exceptions to migration towards the bulge include structural entrapment of hydrocarbons beneath the main frontal thrust zone of FTB and some structural traps beneath the Lower Fiqa Formation.

Organic geochemical studies and origin of black hydrocarbon material (heavy oil) produced from Risha gas field (Jordon): insights into produced contaminated organic-inorganic materials during production

After several years of gas production, a black solid hydrocarbon material began to be produced along with the gas stream from the Risha gas field, in the northeastern part of Jordan. The main reason for the formation of this material is still unknown until this time, so knowing the source of this material is this study’s main goal. Organic geochemical studies for black solid material and effective source rocks (Lower Silurian shales) are used to determine the physical and organic components of the produced black solid material (heavy oil) and attempt to identify its source. The black solid material demonstrates high organic carbon (TOC = 12% by leco instrument) and a high calorific value, like those of oils, asphalts, and shale oils with moderate sulfur content. The gross composition of the black solid material sample is dominated by saturates and asphaltene but contains very low aromatic hydrocarbons reflecting the naphthenic oil type. Meanwhile, the Silurian extracts range between paraffinic and paraffinic-naphthenic organic matters. The biomarker indicators related depositional environment and carbon isotopic composition for the black solid material sample and Silurian extracts, show that they were relatively deposited in a reducing marine environment. The black material reveals lower maturity level than the Silurian extracts. Oil/source rock correlation study for the studied samples suggests strong affinity between the black material and Lower Silurian source rock in their source characteristics, suggesting that the black hydrocarbon material was expelled from the Silurian source rocks at low maturity stage as normal oil. This normal oil is subjected to secondary alteration process (evaporative fractionation) and was stored in the reservoir. It contaminated with some inorganic material that was introduced into the well as a component of a drilling mud additive or drill string lubricant or, potentially, in part, a corrosion product of wellbore tubulars, since significant iron was present in the sample.

The Lower Silurian (Hot Shale) Source Rocks of Western Iraq: Depositional Model and Stratigraphic Distribution

The Hoseiba Member, an Early Silurian basal mature hot shale of the Akkas Formation (Silurian) consists of about 80% of the Paleozoic hydrocarbon potential system, it is organic-rich with total organic carbon up to 16% as the main source for the Paleozoic gas resources in Iraq. The hot shale is the main source of rocks that are penetrated in deep wells in the western Iraqi desert such as Akkas-1, Qaim-1, and Khleisia -1, which are distributed due to paleo uplift in the restricted regional basin in the west, south, and northwest Iraqi desert and wedged to north thrust zone in Ora area of extreme northern Iraq, Ora subbasin to Aljezira NW and in the west where the approved source rocks of ‘Hot shale” Akkas -Widyian subbasin (Rephrase). The Hoseiba Member, basal hot shale in the Akkas Formation in Iraq and their correlative units are extended within neighboring countries Jordan, Syria, Saudi Arabia, Iran, Oman, and south Turkey. Qualitative and quantity of Hot Shales source rocks Silurian are Excellent in Akkas well -1 (0.95-16.62%) TOC in Akk-1 Akkas sub-basin west Iraq and an average thickness (30 m.) with 1-9.94% TOC in Kh-1 Al-Jezira sub-basin NW Iraq. The hot shale distribution was controlled by the Caledonian uplift that created paleo-high in northern Iraq and moderately deep to the northwest, and deep depression deposition in west and south desert Iraq. The hot shale expulsion and migration of hydrocarbon are controlled by the underlying main reservoir of the Khabour Formation K1 sandstone ember by block faulting

Source and thermal maturity assessment of the Paleozoic-Mesozoic organic matter in the Risha gas field, Jordan

Detailed geochemical analyses of the Lower Silurian-Cretaceous shales in the Risha Field were carried out to determine their source input (marine or terrigenous), paleoenvironment, maturity, and hydrocarbon generation potential for their contributions to the gas field. The Lower Silurian shales are believed to be effective source rocks for oil within the Paleozoic petroleum system in the Risha field. Furthermore, the Upper Cretaceous shales have high hydrocarbon potentials and are considered as a promising source for oil and gas. The Upper Ordovician, Lower Silurian and Upper Cretaceous shales in the study area were deposited in a marine anoxic environment, resulting in the accumulation of highly liptinitic organic matters derived from algae and bacteria (Type II kerogen). The maturity of the Lower Silurian source rocks increases from the oil window to the gas window. Ordovician shales have reached the over maturity stage. Current hydrogen index (HI) values for the Silurian organic matter are relatively low after significant hydrocarbon production and expulsion. Two oil types are found from the standard petroleum geochemical analyses of the studied shales: naphthenic oil from immature Cretaceous black shales and high maturity paraffinic oils from Lower Silurian and Ordovician layers. The thermal history model of the Lower Paleozoic source rocks reveals that the Lower Silurian shales reached the dry gas generation stage 280–250 million years ago during Early Triassic, suggesting the large volume of gas accumulated in the Risha field mainly from the Silurian source rocks.

Late Paleozoic-Early Mesozoic paleotectonics of the northern Arabian Plate (SE Turkey) and its role in the Paleozoic petroleum system

The Carboniferous compressional deformation of the Arabian Plate has been causally linked with the Hercynian orogeny. However, this epeirogenic movement occurred far from the Arabian plate. Instead, the Gondwana-directed subduction of the Paleo-Tethys oceanic crust may be the controlling factor of the Carboniferous structural development of southeast Turkey (the northern Arabian Plate). The tectonic activity resulted in uplift and widespread erosion of a large area and produced granitic intrusions, metamorphism, folding, and faulting. The compressional event was intermitted by theback-arc spreading of the Neo-Tethys Ocean (Middle Permian-Triassic) that occurred because of the detachment of the Cimmerian supercontinent from the Gondwana margin. The spreading of the Neo-Tethys caused the Arabian Plate to be subjected to extensional tectonism. The tectonic overprints of these epeirogenic events on the structural fabric of southeast Turkey have not been studied in detail. Innovations in subsurface imaging techniques, wireline logs, and sufficient-quality data enable the depiction of the traces of the Carboniferous compression and the subsequent Permian–Triassic regional extension. This study explores the structural remnants of the Carboniferous compression and the Permian–Triassic extension in southeast Turkey and their impact on the Paleozoic petroleum system. In conclusion, the Carboniferous, SW- and EW-oriented compressional forces led to major uplift, inversion, and substantive erosion in southeast Turkey. The regional uplift confined the Silurian-sourced oil exploration activities to a narrower area due to the denudation of the Silurian units towards the Carboniferous Arches. Subsequently, the opening of the Neo-Tethys yielded en-echelon NW and WNW-trending horsts and grabens bounded on both sides by normal faults, resulting in the northeastward thickening of the syn-rift units. The horst structures allow hydrocarbon accumulation in the Ordovician Bedinan Formation sandstones tectonically juxtaposed with the Silurian source rock.

Petroleum system analysis of the Paleozoic series in the Fars Platform of Iran

The Paleozoic petroleum system of the Fars Platform of Iran is analyzed using 1D petroleum system models of 17 deep wells drilled in the study area. The main aim was to investigate the hitherto undocumented influence of salt tectonics on the essential elements and processes of this petroleum system. For the first time, a better understanding about the geohistory evolution of this prolific petroleum system is provided over the Fars Platform. Modeling results indicate that hydrocarbon generation from the Silurian source rock was associated with salt withdrawal synclines. Salt tectonics further controlled the entrapment styles and the geometric distribution of carrier/reservoir rocks and their overlying evaporitic seals. Our findings provide new insights for identifying the remaining exploration potential in the Paleozoic petroleum system of the Fars Platform and suggest that the role of salt tectonics should be considered in the future basin and petroleum system modeling studies in this area.

Tectono-stratigraphic evolution of the Permo-Triassic succession in the fars platform of Iran: Implications for future exploration of the Paleozoic petroleum system

• Salt tectonics has influenced the Paleozoic petroleum system of the Fars Platform. • Withdrawal synclines control the thickness/facies of the Permo-Triassic sequences. • Considerable potential exists for stratigraphic traps in this petroleum system. Using a new tectono-stratigraphic framework, this paper investigates the Paleozoic petroleum system of the Fars Platform (Southwest Iran). The essential elements and processes of this prolific petroleum system were strongly impacted during both syn -rift and post-rift phases. Extensive erosion during the syn -rift phase led to the local removal of the Latest Ordovician-Earliest Silurian Sarchahan source rock and deposition of continental clastic sediments which acted as important carrier rocks during hydrocarbon migration. During the post-rift phase, syn -depositional salt tectonics predominantly controlled the stratigraphy of the Permo-Triassic strata. The salt- withdrawal synclines not only controlled the facies and thickness of the reservoir-seal couplets, but also promoted hydrocarbon generation from the Silurian source rock in the resulting depocenters. These hydrocarbons could migrate toward structurally higher areas through areally-continuous carriers of the Lower Permian Faraghan Formation and from huge accumulations below efficient evaporitic seals. This model can better explain the present-day distribution of Paleozoic accumulations in the Fars Platform and sheds new light on the remaining potential (in stratigraphic traps) within the Paleozoic petroleum system.

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)

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.

Mineralogical and geochemical imprints to determine the provenance, depositional environment, and tectonic setting of the Early Silurian source rock of the Qusaiba shale, Saudi Arabia

The Early Silurian source rock of the Qusaiba shale from Saudi Arabia was analyzed for its mineralogical and geochemical compositions to investigate its provenance, depositional environment, and tectonic setting, which still has not been studied. The shale is approximately 85 m thick gray to dark gray to black shale intercalated with siltstone and sandstone. The non-clay minerals are quartz and dolomite, while the clay minerals are kaolinite, illite, and smectite in some samples. An intermediate igneous source is suggested for the Qusaiba shale based on the Al2O3/TiO2 ratio, calculated SiO2, and Zr–TiO2, Al2O3–TiO2, SiO2–Al2O3/TiO2 and Cen–La/Ybn binary plots. The Zr/Sc versus Th/Sc cross plot indicate that the Qusaiba shale was not subjected to sedimentary recycling. The abundance of kaolinite, C–values [Σ(Mn + Fe + Ni + Cr + Co + V)/Σ(Mg + Ca + Sr + Ba + Na + K)], Sr/Cu ratios and high chemical index of alteration (CIA) values indicate humid and warm conditions for the period of deposition. Geochemical proxies such as V–Al2O3 and P2O5–Al2O3 binary plots suggest a shallow marine depositional environment for the Qusaiba shale was prevailing during the Paleozoic in northeastern Gondwana. The Qusaiba shale represents a transgressive phase in the Early Silurian followed the Late Ordovician regressive event marked by the glacial non-marine sandstone of the Sarah Formation. The Qusaiba Formation shows another regressive event characterized by storm deposits at its top. The tectonic setting interpreted from major oxides, ratios of immobile–trace elements and rare earth elements (REE) parameters such as (La/Y)n, (La/Y)n, (Gd/Yb)n and Eu/Eu* depicts a passive margin matching with the regional setting for the northeastern Gondwana. Illite contents (13 %–33%) and IC values (0.52°–0.75° Δ2θ) suggest a late diagenesis stage for the Qusaiba shale.

Petroleum source rocks of the Silurian deposits on the Chernov swell (Timan‑Pechora basin)

Silurian source rocks are among the least studied in the Timan-Pechora basin. This is mainly due to their occurrence at great depths (3.0–4.5 km) and the limited penetration of this stratigraphic interval by wells. Another source of information is the outcrops of the Silurian, which are known in the eastern and northeastern parts of the Timan-Pechora basin. The studied section of the Silurian deposits is exposed on the Padimeityvis River, located on the Chernov swell in the northeastern part of the basin. This article is devoted to the study of Silurian source rocks based on the results of lithological, coal petrographic studies and geochemistry of organic matter. The studied section is composed of carbonate and clay-carbonate deposits formed in shallow-water shelf conditions. Most of the section, composed of microcrystalline and microcrystalline with bioclasts limestones, is characterized by low concentrations of organic matter (Corg is generally less than 0.3 %). Elevated Corg contents (up to 1.16 %) are characteristic of clay-carbonate rock varieties, which make up about 20 % of the section. Sediments with increased concentrations of organic matter were formed in isolated and deepened areas of the bottom of the shallow-water basin as a whole. Assessment of the catagenetic transformation based on Rock-Eval pyrolysis data, coal petrographic studies, and conodont color indices showed that organic matter reached the conditions of the middle-end of the main oil generation zone (gradation MC2‑MC3). The obtained geochemical characteristics (Corg, S2, HI), taking into account a certain level of organic matter maturity, indicate that the Silurian source rocks had an average hydrocarbon potential.

Origin of conventional and shale gas in Sinian–lower Paleozoic strata in the Sichuan Basin: Relayed gas generation from liquid hydrocarbon cracking

Large amounts of natural gas have been discovered recently, both in carbonate reservoirs and in shales in the Sinian–Silurian strata of the Sichuan Basin, southern China. Although numerous studies have been conducted to learn about the accumulation of conventional and shale gas, the gas generation history, the origins of the two types of gas, and gas resources in the basin remain unclear. In this study, the hydrocarbon generation histories of Cambrian and Silurian source rocks were reconstructed on the basis of thermal history and hydrocarbon generation kinetic parameters. Intensive cracking of crude oil to generate considerable amounts of secondary cracking gas in Silurian and Cambrian formations occurred during deep burial. The high abundance of overmature pyrobitumen in carbonate reservoirs and shale demonstrates the occurrence of large-scale in situ cracking of liquid hydrocarbons. A mixing model was proposed to quantitatively determine the contribution of kerogen and oil-cracking gas in shale gas accumulations. The mixing of two thermogenic gases with different maturities resulted in a reversal and a rollover of the carbon isotope compositions of shale gas. Moreover, gas resources from the cracking of three occurrence states of liquid hydrocarbons—including dispersed residual bitumen in source rocks, dispersed oil outside the source, and accumulated oil in reservoirs—were evaluated in Sinian–Cambrian and Silurian petroleum systems in the Sichuan Basin, providing a guide for future deep gas exploration of similar formations in China and elsewhere.

Burial and thermal history of the Lower Palaeozoic petroleum source rocks at the SW margin of the East European Craton (Poland)

Thermal maturity modelling was carried out in over sixty wells along the SW margin of the East European Craton (EEC). The burial and thermal history modelling of the EEC, using thermochronological data, allowed the construction of burial history maps showing its geological development in the Phanerozoic. These results have proved that the Ordovician and Silurian source rocks occurring at the SW margin of the EEC reached a maximum palaeotemperature in the Palaeozoic, mainly during Devonian–Carboniferous time and at the latest during the Silurian in the most westerly part of this margin, along the Teisseyre-Tornquist Zone. In Mesozoic and Cainozoic time, the Ordovician and Silurian strata generally were subjected to cooling or to very minor heating, certainly below the Variscan level. The maximum burial and maximum temperature of the Ediacaran–Lower Palaeozoic strata were reached during the Early Carboniferous in the Baltic Basin and during the Late Carboniferous in the Lublin area, and even in the Early Permian in the SE corner of the Lublin Basin. Thus, the main period of maturation of organic matter and hydrocarbon generation in the Ordovician and Silurian source rocks was in the Late Palaeozoic (mainly Devonian–Carboniferous) and in the westernmost zone along the Teisseyre-Tornquist line at the end of the Silurian.

Petroleum generation and expulsion in the Lower Palaeozoic petroleum source rocks at the SW margin of the East European Craton (Poland)

In this work, 1-D numerical modelling of petroleum generation and expulsion processes in the Upper Ordovician and Lower Silurian source rocks was carried out in over sixty wells along the SW margin of the East European Craton ( EEC) in Poland. Lower Palaeozoic sediments were subjected to rapid burial in the Palaeozoic and then were uplifted in several phases, but with the predominance of the late Variscan tectonic inversion. The thermal maturity of organic matter in the Lower Palaeozoic strata indicates the advancement of the generation processes from the phase of low-temperature thermogenic processes in the NE part of the Baltic and Podlasie-Lublin basins to the overmature stage along the zone adjacent to the Teisseyre-Tornquist Zone (TTZ). The results of modelling of generation and expulsion show that these processes took place mainly in the Devonian and Carboniferous periods and in the westernmost part (along the TTZ), even in the latest Silurian. The hydrocarbon expulsion took place with a small – delay after generation. During the Mesozoic and Cainozoic, generation processes practically were not resumed or intensified. Nevertheless, it was found that zones with an increased shale gas potential can occur only in a relatively narrow belt on the SW slope of the EEC, parallel to the edge of the TTZ. The most promising seem to be Caradocian, Llandovery and the Wenlock between the Lebork IG-1 and Kościerzyna IG-1 wells in the Baltic Basin, and the Wenlock source rocks in the Podlasie-Lublin Basin between the Okuniew IG-1, Łopiennik IG-1 and Narol IG-1 wells. Most of the hydrocarbons were subjected to expulsion and possible migration. As a result, there was a large dispersion of the hydrocarbons generated. The chance of preservation of these hydrocarbons in the source rocks is small.

NON‐DESTRUCTIVE INVESTIGATIONS OF THE THERMAL MATURITY AND MECHANICAL PROPERTIES OF SOURCE ROCKS

Source rocks consist of diverse lithofacies whose composition can vary according to the depositional environment and the provenance of the sediment composing the rock matrix. In general, the rock fabric is made up of very fine grained, laminated and non‐laminated intervals composed of authigenic, detrital and biogenic minerals, together with organic matter consisting of kerogen, bitumen and pyrobitumen. During burial, exposure to elevated temperatures and pressures transforms the kerogen in a source rock into hydrocarbons. This transformation is tracked according to different stages of maturity, and results in increases in both the porosity and aromaticity of the kerogen within the rock and the formation of pyrobitumen. Little is understood about how these changes affect the mechanical properties of the organic matter contained in the rock, or to what degree this also influences bulk rock mechanical moduli. Understanding this relationship is essential to determine the production potential of a “source rock reservoir”, i.e. an unconventional self‐sourced reservoir from which oil and gas can be recovered through hydraulic fracturing of the rock matrix. Direct measurement of the mechanical properties of organic matter in relation to its thermogenic transformation, however, is a challenge due to the small size of the materials composing the rock fabric, especially with source rocks that are finely laminated. To explore this relationship, the results of a non‐destructive, dual‐mode examination of source rock maturity and kerogen mechanical properties is presented using Raman spectroscopy and Atomic Force Microscopy (AFM), respectively. The analysed samples (n = 5) are a Silurian source rock from the Middle East. The results demonstrate the ability to measure both mechanical moduli and thermal maturity of organic components in intact source rock samples which range in maturity from the catagenesis through the metagenesis stages i.e %Ro from 0.6 to 1.6. These techniques provide an opportunity to examine kerogen, bitumen and pyrobitumen properties at the micro‐ and nano‐scale using intact rock samples without disruption of the rock fabric, which readily occurs with conventional bulk core analysis techniques.

Tectono-thermal Evolution of the Lower Paleozoic Petroleum Source Rocks in the Southern Lublin Trough: Implications for Shale Gas Exploration from Maturity Modelling

The Lower Paleozoic basins of eastern Poland have recently been the focus of intensive exploration for shale gas. In the Lublin Basin potential unconventional play is related to Lower Silurian source rocks. In order to assess petroleum charge history of these shale gas reservoirs, 1-D maturity modeling has been performed. In the Łopiennik IG-1 well, which is the only well that penetrated Lower Paleozoic strata in the study area, the uniform vitrinite reflectance values within the Paleozoic section are interpreted as being mainly the result of higher heat flow in the Late Carboniferous to Early Permian times and ~3500 m thick overburden eroded due to the Variscan inversion. Moreover, our model has been supported by zircon helium and apatite fission track dating. The Lower Paleozoic strata in the study area reached maximum temperature in the Late Carboniferous time. Accomplished tectono-thermal model allowed establishing that petroleum generation in the Lower Silurian source rocks developed mainly in the Devonian – Carboniferous period. Whereas, during Mesozoic burial, hydrocarbon generation processes did not develop again. This has negative influence on potential durability of shale gas reservoirs.

Geochemical characteristics and reservoir continuity of Silurian Acacus in Ghadames Basin, Southern Tunisia

The present work is dealing with the study of lateral and vertical continuity of the multi-layers Acacus reservoir (Ghadames Basin-Southern Tunisia) using the distribution of hydrocarbon fraction. For this purpose, oil–oil and source rock–oil correlations as well as the composition of the light fractions and a number of saturate and aromatic biomarkers parameters, including C35/C34 hopanes and DBT/P, have been investigated.Based on the ratios of light fraction and their fingerprints, the Acacus reservoir from Well1 and Well2 have found to be laterally non-connected although the hydrocarbons they contain have the same source rock. Moreover, the two oil samples from two different Acacus reservoir layers crossed by Well3-A3 and A9, display a similar hydrocarbons distribution, suggesting vertical reservoir continuity.On the other hand, the biomarker distributions of the oils samples and source rocks assess a Silurian “Hot shale” that is the source rock feeding the Acacus reservoir. The biomarker distribution is characterized by high tricyclic terpanes contents compared to hopanes for the Silurian source rock and the two crude oils. This result is also confirmed by the dendrogram that precludes the Devonian source rocks as a source rock in the study area.

Biomarkers and C and S Isotopes of the Permian to Triassic Solid Bitumen and Its Potential Source Rocks in NE Sichuan Basin

The potential parent source rocks except from Upper Permian Dalong Formation (P3d) for Upper Permian and Lower Triassic solid bitumen show high maturity to overmaturity with equivalent vitrinite reflectance (ERo) from 1.7% to 3.1% but have extractable organic matter likely not contaminated by younger source rocks. P3d source rocks were deposited under euxinic environments as indicated by the pyrite δ34S values as light as -34.5‰ and distribution of aryl isoprenoids, which were also detected from the Lower Silurian (S1l) source rock and the solid bitumen in the gas fields in the west not in the east. All the solid bitumen not altered by thermochemical sulfate reduction (TSR) has δ13C and δ34S values similar to part of the P3l kerogens and within the S1l kerogens. Thus, the eastern solid bitumen may have been derived from the P3l kerogens, and the western solid bitumen was likely to have precracking oils from P3l kerogens mixed with the S1l or P3d kerogens. This case-study tentatively shows that δ13C and δ34S values along with biomarkers have the potential to be used for the purpose of solid bitumen and source rock correlation in a rapidly buried basin, although further work should be done to confirm it.

Нефтегазоматеринские породы силурийских и нижнедевонских отложений западной части поднятия Чернова

Нефтегазоматеринские породы силурийских и нижнедевонских отложений западной части поднятия Чернова