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The Ordovician system of the Ordos Basin is rich in oil and gas resources, but the tectonic evolution of Ordovician strata and controls on natural gas generation and accumulation are poorly understood. In this study, we integrate field observations, seismic and drill core interpretation, and geochemical data analysis [total organic carbon (TOC) and vitrinite reflectance (Ro)] to address this issue. Results show a clear depositional axis, with thick (>2500 m) Ordovician sediments in the southern half of the basin, and thinner strata in the central and northern parts. Ro values range from 2.04% to 3.45%, and 55 of 73 samples have TOC > 0.23 wt%. Our novel findings made as below: (i) Ordovician strata have high contents of organic matter and that thermal evolution reached the dry gas stage, favorable for natural gas generation. (ii) Ordovician strata have recorded multiple tectonic events and experienced erosion that resulted in the formation of a karst type residuum in the central and northeastern parts of the basin. (iii) An Early Cretaceous tectono-thermal event controlled the generation and accumulation of natural gas, and this was the peak period of gas generation of Ordovician strata. (iv) Natural gas accumulation and adjustment occurred during the Cretaceous and Cenozoic, respectively. The Ordos Basin has experienced strong deformation and denudation since the Late Cretaceous. Collectively, the deformation was more intense in the south and weaker in the north, preventing hydrocarbon preservation in the southern part of the basin. These findings provide new insights to guide oil and gas exploration of the Ordos Basin.

The impact of tectonic activities from different tectonic zones on hydrocarbon generation in the Upper Jurassic Naokelekan Formation was addressed in this study. The Upper Jurassic Naokelekan Formation is an important potential of source rocks for hydrocarbon generation that charges most of the Cretaceous and younger reservoirs in the Kurdistan Region, Iraq. A total of 5 rock specimens from the Warte outcrop and 7 cutting samples from Well Bina Bawi-1 were collected for Rock-Eval pyrolysis to investigate the relationship between the ability of the formation to generate hydrocarbons and tectonic activities. The results of Rock-Eval analysis on the analyzed samples showed an average of 2.65 wt% and 0.9 wt% total organic carbon (TOC) for Warte and Well Bina Bawi-1, respectively. Based on the TOC data, the Naokelekan Formation, in general, has a good to very good source rock potential. The qualitative properties of the organic matter (OM) of the formation were inferred from the kerogen types. The Warte section mostly contains type III kerogen that is gas prone, whereas the Well Bina Bawi-1 section contains mixed type I-II kerogen that is oil prone. It should be taken into consideration that the values for the hydrogen index (HI) of the Warte section are unreliable for interpretation of the organic type, because the HI is considerably reduced owing to the high level of thermal maturity. The Tmax values showed that the Warte section is thermally more mature than the Well Bina Bawi-1 section. The difference in the thermal maturity can likely be attributed to the differential effects of the tectonic activities on the studied areas. Depending on the proximity or distance of the area in relation to the subduction zone, the sediments in the Imbricated Zone were more affected by the tectonic activities than the sediments in the High Folded Zone. Accordingly, the main factors that might have caused a higher thermal maturity in the Imbricated Zone include a high paleo heat flow, overthrusting, and hydrothermal activities.

Carbonates have been known to act as hydrocarbon source rocks, but their basic geochemical and associated hydrocarbon generation characteristics remain not well understood as they occur with argillaceous source rocks in most cases, and the hydrocarbon generation from each rock type is difficult to distinguish, forming one of puzzling issues within the field of petroleum geology and geochemistry. To improve the understanding of this critical issue, this paper reviews recent advances in this field and provides a summary of key areas that can be studied in future. Results show that carbonate source rocks are generally associated with high-salinity environments with low amounts of terrestrial inputs and low dissolved oxygen contents. Petrographically, these source rocks are dark gray or black, fine-grained, stratified, and contain bacterial and algal bioprecursors along with some other impurities. They generally have low organic matter contents, although these can vary significantly in different cases (e.g., the total organic carbon contents of marine and lacustrine carbonate source rocks in China are generally 0.1%–1.0% and 0.4%–4.0%, respectively). These rocks contain type I and type II kerogen, meaning there is a lack of vitrinites. This means that assessment of the maturity of the organic matter in these sediments needs to use non-traditional techniques rather than vitrinite reflectance. In terms of molecular geochemistry, carbonate source rocks have typical characteristics indicative of generally reducing and saline environments and lower organism-dominated bioprecursors of organic matter, e.g., high contents of sulfur compounds, low Pr/Ph ratios, and dominance of n-alkanes. Most of the carbonate source rocks are typically dominated by D-type organic facies in an oxidized shallow water mass, although high-quality source rocks generally contain A- and B-type organic facies in saline lacustrine and marine-reducing environments, respectively. The hydrocarbon generation model for the carbonate source rocks can involve early, middle, and late stages, with a diversity of hydrocarbons within these rocks, which can be aggregated, adsorbed, enclosed within minerals, or present as inclusions. This in turn implies that the large-scale hydrocarbon expulsion from these rocks is reliant on brittle deformation caused by external forces. Finally, a number of aspects of these source rocks remain unclear and need further study, including the effectiveness of carbonates as hydrocarbon source rocks, bioprecursors, and hydrocarbon generation models of carbonate source rock, and the differences between marine and lacustrine carbonate source rocks.

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.

Lacustrine mudrocks are composed of minerals and organic matter (OM). The origin and preservation of OM are two controlling factors of the hydrocarbon generation capacity of mudrocks. It is a key method in source rock research to study the deposition process from the view of the OM and sedimentary environment. Following this idea, the reason for the discrepancy in hydrocarbon production between the northern and the southern part of Dongpu Sag is analyzed and discussed. The lacustrine mudrocks of the Shahejie Formation in Dongpu Sag are sampled and analyzed for information about mineralogy, microstructure, elemental geochemistry, and OM characteristics. The mudrocks are then divided into three lithofacies: silt-rich massive mudstone, homogeneous massive mudstone, and laminated mudstone. Each lithofacies shows distinct characteristics, and the hydrocarbon generation ability of them increases in sequence. Further discussion that the differences in hydrocarbon generation are caused by the sedimentary environment. The water depth, salinity, and reducibility of the sedimentary environments of these three lithofacies increase in sequence, as well. The correlation analysis indicates that it is the environment that controls the origin, accumulation, and preservation of OM in each lithofacies and then causes the great differences in hydrocarbon generation capacity. In Dongpu Sag, the proportion of laminated mudstone is much higher in the northern part, which leads to greater oil/gas production than the southern part. In research of source rocks, both the lithofacies characteristics and the sedimentary environments that control the characteristics should be studied.

The Jinyang Basin is a typical volcanic-sedimentary basin, located in the southern peripheral area of the Songliao Basin. Hydrothermal activity is often closely related to the intrusion or eruption of magma. It was recently suggested that dolomite in the Jurassic Beipiao Formation was formed under the influence of magmatic-hydrothermal activity and magmatic-hydrothermal activity might have impacts on the organic matter of the source rocks. No investigation has been aimed at the effect of magmatic-hydrothermal activities on the accumulation of organic matter in the Beipiao Formation source rocks and a comprehensive study is urgent, which would be indicative in unravelling the accumulation mechanism of organic matter and useful in further petroleum exploration. To provide important insights into these issues, we carried out a detailed investigation of geological and geochemical analysis for Wolong (WL) and Dongkuntouyingzi (DK) outcrop shales from the Lower Jurassic Beipiao Formation in the Jinyang Basin. The hydrothermal indicator discrimination diagram (Zn-Ni-Co triangular plot) and rare earth element anomalies (δEu and δCe) indicate that the formation of WL samples is associated with hydrothermal activity, but DK is not. The TOC values suggest that most of the WL and DK samples are good to very good and fair to good source rocks, respectively. The Ro values suggest that both WL (Ro = 1.17%) and DK (Ro = 1.01%) samples have entered the oil-generating stage, and WL samples were influenced by the magmatic activity with higher maturity. The biomarkers such as high steranes/hopanes, high 4-methyl steranes/C29 steranes, low Pr/Ph values and high gammacerane index suggest that WL samples were deposited in an anoxic-prone saline environment with significant contributions of algal sources. Contrarily, the DK samples were deposited in oxic-prone and freshwater paleolake with significant contributions of terrigenous organic matter. The magmatic-hydrothermal activities in the Wolong area brought numerous nutrients to the lake basin, which may facilitated the reproduction of aquatic organisms. At the same time, the magmatic-hydrothermal activities increased the salinity of water and promoted the formation of a water reducing environment, which provided an excellent environment for the preservation and enrichment of organic matter. Therefore, the magmatic-hydrothermal activities in the Wolong area promoted the formation of organic-rich source rocks and the hydrocarbon generation process.

The study area is located on southeastern boundary of the intracratonic Parana Basin, in the northeastern region of Rio Grande do Sul State, Brazil. The study of organic matter characterization and its distribution in relation to the sequence stratigraphy method is of great importance for the identification of possible target or inappropriate areas for exploration on the eastern border of this basin. Three boreholes were analysed in this work and sample sets were collected from the sedimentary section covering a Permian stratigraphic interval, from sequences II, III and IV (between the base of Rio Bonito Formation and the top of Teresina Formation). Results of this work evidence that: the concentration and composition of the dispersed organic matter (DOM) in the sedimentary package is associated with production, dilution, preservation and degradation of the organic matter; the organic fragments preserved in sedimentary rocks are predominantly composed of a mixture of particles of the inertinite group and lesser amounts from the vitrinite group, both derived from terrestrial plants; consequently, the hydrogen and oxygen indexes are low; since the kerogen type is II and IV, it does not contribute to the generation of oil. The organic matter distribution within the analysed sequence stratigraphic shows the following general trend or behaviour: 1) total organic carbon, hydrogen index and vitrinite group contents are relatively high in the rocks of the transgressive system but are lower in rocks of the lowstand and highstand systems; 2) the Inertinite group contents show the opposite trend, with the highest concentrations in the rocks of the lowstand and the highstand systems. The results of this work also evidence that in the upper strata of Rio Bonito Formation the OM is immature but should have reached the oil window (catagenesis) in the strata located below this formation.

Domanic Upper Devonian deposits of the Timan-Pechora petroleum province are the subject of growing scientific and practical interest from the time of its discovery (late 19th century). And, despite the considerable knowledge database on Domanic organic matter have accumulated geochemists, it still requires more detailed study. This article presents the geochemical characteristics of organic matter of Timan-Pechora Domanic source rock using Rock Eval pyrolysis and the kinetic spectra of kerogen decomposition of sedimentary deposits from different parts of the Timan-Pechora basin. The variety of Domanic kinetics by deep strata and by area of the Timan-Pechora basin were analyzed. Dependence of kinetics from sedimentation conditions is shown. Four regional (sublatitudinal and submeridional) 2D basin models were created using of geochemical results. The results of petroleum basin modelling are performed. The sensitivity study of basin models to the kinetic spectrum change was made. It is shown that use of measured Domanic kinetics instead of published in software kinetics significantly affects basin modelling results. Were estimated the volume of generated by Domanic source rock hydrocarbons with use of different kinetics (published and measured). The difference in Domanic generation between these two scenarios is about 70 Bt of oil.

The lignite and associated shale of the Khadsaliya Clays Formation (Eocene) of Saurashtra Basin, India have been studied. Organic petrographic, palynofacies and organic geochemical analyses have been carried out to deduce the depositional palaeoenvironment, including the assessment of the hydrocarbon potential of this sequence. Petrographically, the lignites constitute huminite macerals in dominance (ay. 60%). The organic facies, as derived from maceral composition and biomarker data, suggests that the peat biomass was formed from woody forest vegetation consists of angiosperms and pteridophytes. Microbial activity was also prominent over the peat biomass. The peat biomass was deposited in tropical-subtropical humid climatic conditions under deltaic control and brackish water influence. Further, there are signatures of intermittent floods in the mire, and is evident from the shift from mesotrophic to rheotrophic conditions. The organic matter has been categorized into two palynofacies and is derived from degraded terrestrial biomass. The extrapolation of Tyson's APP diagram and Pr/n-C-17 vs. Ph/n-C-18 plot suggest that deposition took place in dysoxic to sub-oxic conditions. The huminite reflectance values (0.30-0.38%, ay. 034% R-r) suggest that lignites are less mature and have reached up to lignitic stage (low rank B) of coalification. The geochemical (proximate + ultimate) analyses reveal that the lignites are characterized by high moisture content (ay. 18%) and relatively low ash yield (ay. 27%). The volatile matter yields and carbon contents are moderately high, whereas fixed carbon, sulphur and oxygen contents are average and hydrogen and nitrogen contents are relatively low. Rock-Eval pyrolysis data indicate that the hydrogen index values of the samples vary between 23 and 477 mg HC/g TOC (ay.188 mg HC/g TOC). The Tniax values of the lignites range between 377 and 433 degrees C (ay. 418 degrees C), along with the presence of beta beta hopanes suggesting the immature nature of the deposits. HI vs. T-max, S2 vs. TOC, HI vs. Ol and H/C vs. O/C plots of the studied samples indicate that the organic matters are a mix of type II/Ill kerogens. The types of kerogen along with high TOC contents (ay. 33 wt.%) indicate the ability of lignite-bearing sequence of Khadsaliya to generate mix of oil/gaseous hydrocarbons upon maturation. (C) 2017 Elsevier B.V. All rights reserved.

Large volumes of hydrocarbons reside in volcanically influenced sedimentary basins. Despite having a good conceptual understanding of how magmatism impacts the petroleum systems of such basins, we still lack detailed case studies documenting precisely how intrusive magmatism influences, for example, trap development and reservoir quality. Here we combine 3D seismic reflection, borehole, petrographical and palaeothermometric data to document the geology of borehole 5/22-1, NE Irish Rockall Basin, offshore western Ireland. This borehole (Errigal) tested a four-way dip closure that formed to accommodate emplacement of a Paleocene–Eocene igneous sill-complex during continental break-up in the North Atlantic. Two water-bearing turbidite-sandstone-bearing intervals occur in the Upper Paleocene; the lowermost contains thin (c. 5 m), quartzose-feldspathic sandstones of good reservoir quality, whereas the upper is dominated by poor-quality volcaniclastic sandstones. Palaeothermometric data provide evidence of anomalously high temperatures in the Paleocene–Eocene succession, suggesting the poor reservoir quality within the target interval is likely to reflect sill-induced heating, fluid flow, and related diagenesis. The poor reservoir quality is also probably the result of the primary composition of the reservoir, which is dominated by volcanic grains and related clays derived from an igneous-rock-dominated, sediment source area. Errigal appeared to fail due to a lack of hydrocarbon charge: that is, the low bulk permeability of the heavily intruded Cretaceous mudstone succession may have impeded the vertical migration of sub-Cretaceous-sourced hydrocarbons into supra-Cretaceous reservoirs. Break-up-related magmatism did, however, drive the formation of a large structural closure, with data from Errigal at least proving high-quality, Upper Paleocene deep-water reservoirs. Future exploration targets in the NE Irish Rockall Basin include: (i) stratigraphically trapped Paleocene–Eocene deep-water sandstones that onlap the flanks of intrusion-induced forced folds; (ii) structurally trapped, intra-Cretaceous, deep-water sandstones incorporated within intrusion-induced forced folds; and (iii) more conventional, Mesozoic fault-block traps underlying the heavily intruded Cretaceous succession (e.g. Dooish). Similar plays may exist on other continental margins influenced by break-up magmatism. Supplementary material: Borehole-related reports, and litho- and composite logs are available at https://doi.org/10.6084/m9.figshare.c.4803267

Deep trough lie at the base of the sedimentary basins of the Arctic, which for a long geological time remained the epicenter of the immersion and the area of accumulation of large sedimentation strata, often exceeding 10-15 kilometers. Deep troughs extend long distances from the basin to the basin. In their limits, the deposition occurred of both the ancient Paleozoic basins and the younger Meso-Cenozoic basins. The main sedimentary material was transported along the immersion areas;centers of oil and gas generation were formed. The width of such trough is 100-200 km, and the length reaches 1000 km or more. Deep faults along the troughs often exhibited shear deformations, and at the boundary of the restructuring from one basin to another, fold-thrust deformations occurred. As a result, under the young sedimentary cover, more ancient fold-thrust structures are traced, stretched often along the axis of deflection.At all stages of basin development, potential oil and gas deposits were built, which generated hydrocarbons. The features of the tectonic structure of the basins and the nature of hydrocarbons migration make it possible to forecast the search for new accumulations of oil and gas. In the Paleozoic basins, the search should focus on border structures, stratigraphically and tectonically limited traps associated with stratigraphic non-conformities and the emergence of ancient rocks beneath the erosion surface. In the Mesozoic basins, the traps are often associated with strata filling theterrigenous sediments, where lithological traps are widespread both in various debris cones, and in the areas of Mesozoic rocks adjacent to older sediments. In the Cenozoic basins of the eastern sector of the Russian Arctic region, the search for hydrocarbons should be conducted at large anticlinal uplifts.

This study presents results for pyrolysis experiments conducted on immature Type II and IIs source rocks (Kimmeridge Clay, Dorset UK, and Monterey shale, California, USA respectively) to investigate the impact of high water pressure on source rock maturation and petroleum (oil and gas) generation. Using a 25 ml Hastalloy vessel, the source rocks were pyrolysed at low (180 and 245 bar) and high (500, 700 and 900 bar) water pressure hydrous conditions at 350 °C and 380 °C for between 6 and 24 h. For the Kimmeridge Clay (KCF) at 350 °C, Rock Eval HI of the pyrolysed rock residues were 30–44 mg/g higher between 6 h and 12 h at 900 bar than at 180 bar. Also at 350 °C for 24 h the gas, expelled oil, and vitrinite reflectance (VR) were all reduced by 46%, 61%, and 0.25% Ro respectively at 900 bar compared with 180 bar. At 380 °C the retardation effect of pressure on the KCF was less significant for gas generation. However, oil yield and VR were reduced by 47% and 0.3% Ro respectively, and Rock Eval HI was also higher by 28 mg/g at 900 bar compared with 245 bar at 12 h. The huge decrease in gas and oil yields and the VR observed with an increase in water pressure at 350 °C for 24 h and 380 °C for 12 h (maximum oil generation) were also observed for all other times and temperatures investigated for the KCF and the Monterey shale. This shows that high water pressure significantly retards petroleum generation and source rock maturation. The retardation of oil generation and expulsion resulted in significant amounts of bitumen and oil being retained in the rocks pyrolysed at high pressures, suggesting that pressure is a possible mechanism for retaining petroleum (bitumen and oil) in source rocks. This retention of petroleum within the rock provides a mechanism for oil-prone source rocks to become potential shale gas reservoirs. The implications from this study are that in geological basins, pressure, temperature and time will all exert significant control on the extent of petroleum generation and source rock maturation for Type II source rocks, and that the petroleum retained in the rocks at high pressures may explain in part why oil-prone source rocks contain the most prolific shale gas resources.

This study investigates the shale gas characteristics of the Permian Barren Measures Formation (Gondwana Supergroup) in the West Bokaro sub-basin of the Damodar Valley Basin, eastern India. A total of 23 core shale samples collected from a borehole located in the western part of the sub-basin were analysed using organic geochemical techniques and scanning electron microscopy. The samples are black carbonaceous shales composed chiefly of quartz, mica and clay minerals. Rock-Eval pyrolysis data show that the analysed samples contain a mixture of Type II and Type III kerogen with TOC values of 2.7 to 6.2%. Rock-Eval Tmax values ranging from 443 to 452 °C correspond to calculated vitrinite reflectance of approximately 0.8–0.9%. A cross-plot of hydrogen index versus Tmax indicates that the samples have reached peak oil to wet gas maturities. A pristane/n-C17 versus phytane/n-C18 cross-plot, together with biomarker parameters such as the dominance of C29 over C27 and C28 steranes and high moretane/hopane ratios (0.22–0.51), demonstrate that the shale samples contain terrigenous organic matter deposited in a suboxic environment. Scanning electron microscopy images of shale samples show the presence of a complex, mostly intergranular pore network. Both micropores (>0.75μm) and nanopores (

Первинна газоносність вугленосної товщі визначається тектонічним режимом, що впливає на фаціальні умови торфонакопичення, особливості петрографічного складу вугілля, його відновленість. Газоносність залежить також від ступеню вуглефікації, що разом з петрографічним складом і відновленістю визначає газогенераційний потенціал і сорбційні властивості вугілля., Primary gas content of the coal-bearing series is determined by tectonic conditions affecting facial conditions of peat accumulation, the features of coal petrographic composition, recovery. Gas content also depends on coalification that along with petrographic composition and recovery determines a gas generation potential and sorption properties of coals.

in deep basins. This requires analysis of gas samples directly tied to specifi c stages of the geologic history of thermally mature basins. Methane-rich hydrocarbon and aqueous fl uid inclusions can provide such samples because they form in fracture-fi lling and diagenetic minerals during the extended history of gas generation, migration, and accumulation (Becker et al., 2010; Mullis et al., 1994; Parris et al., 2003). Unfortunately, inclusions frequently occur in complex, intersecting healed microfractures, often obscuring the less common primary inclusions (Parris et al., 2003), and making it diffi cult to determine the sequence of evolving temperature, pressure, and gas composition. Here we apply molecule-specifi c multimodal threedimensional (3-D) nonlinear microscopy to provide chemically and spatially resolved imaging of assemblages of methane-rich fl uid inclusions and associated crystallographic features, as well as in situ detection of higher hydrocarbons. These observations advance our ability to track gas generation and migration processes within deep basins. METHODS AND SAMPLES

The Ordos Basin of North China is not only an important uranium mineralization province, but also a major producer of oil, gas and coal in China. The genetic relationship between uranium mineralization and hydrocarbons has been recognized by a number of previous studies, but it has not been well understood in terms of the hydrodynamics of basin fluid flow. We have demonstrated in a previous study that the preferential localization of Cretaceous uranium mineralization in the upper part of the Ordos Jurassic section may have been related to the interface between an upward flowing, reducing fluid and a downward flowing, oxidizing fluid. This interface may have been controlled by the interplay between fluid overpressure related to disequilibrium sediment compaction and which drove the upward flow, and topographic relief, which drove the downward flow. In this study, we carried out numerical modeling for the contribution of oil and gas generation to the development of fluid overpressure, in addition to sediment compaction and heating. Our results indicate that when hydrocarbon generation is taken into account, fluid overpressure during the Cretaceous was more than doubled in comparison with the simulation when hydrocarbon generation was not considered. Furthermore, fluid overpressure dissipation at the end of sedimentation slowed down relative to the no-hydrocarbon generation case. These results suggest that hydrocarbon generation may have played an important role in uranium mineralization, not only in providing reducing agents required for the mineralization, but also in contributing to the driving force to maintain the upward flow.

Since the first drill in 1957, three oil, 19 gas and condensate fields have been discovered in the Thrace Basin. However, any petroleum system with its essential elements and processes has not been assigned yet. This study consists of two parts, (1) geochemical overview of the previous work in order to get a necessary help to construct a petroleum system and (2) calculation of quantitative undiscovered hydrocarbon resources generated from this system. An extensive overview study showed that the primary reservoir and source rocks in the Thrace Basin are the Middle Eocene Hamitabat sandstones and shales, respectively, hence it appears that the most effective petroleum system of the Thrace Basin becomes the Hamitabat (!) petroleum system. Currently, 18.5 billion m3 of in-place gas, 2.0 million m3 (12.7 million bbl) in-place waxy oil as well as minor amount of associated condensate were discovered from this system. This study showed that the regional distribution of the oil and gas fields almost overlapped with the previously constructed pod of active Hamitabat shales implying that short and up-dip vertical migration pathway of hydrocarbons from the source to trapping side was available. Thermal model demonstrated that hydrocarbon generation from the Hamitabat shales commenced in the Early Miocene. The amount of quantitative gas generation based on the mean-original TOC = 0.94 wt%, mean-original HI = 217 HC/g TOC and the volume of the pod of active source rock = 49 km3 is approximately 110 billion m3 of gaseous hydrocarbons that results in a high generation-accumulation efficiency of 17% when 18.5 billion m3 of already discovered hydrocarbons are considered. © 2008 Elsevier Ltd. All rights reserved.

The emergence of shale gas as potential hydrocarbon resource has changed the global energy landscape. Fourier Transform Infrared (FTIR), X-ray diffraction (XRD), X-ray florescence (XRF) and Scanning Electron Microscope (SEM) characteristics of thirty nine borehole shale samples belonging to the Barakar (Lower Permian), Barren Measures (Upper Permian) and Raniganj (Upper Permian) Formations from different parts of Raniganj basin, India were studied. FTIR analysis indicates the presence of aromatic hydrogen, aromatic carbon, aliphatic C-H stretching, aliphatic C-H bending, OH functional group within the organic matter and presence of kaolinite, quartz and carbonates within the studied samples. XRF studies indicate that the shales have undergone intermediate to strong weathering condition, and are marked by presence of clay minerals mainly illite and kaolinite. In addition to illite, kaolinite and quartz, alkali feldspar, siderite and calcite were identified within the shales through XRD. Marked development of amorphous character was noted in the XRD plot of one heat affected shale sample. FTIR analysis of this sample also indicates removal of aliphatics and disordering of kaolinite within the sample due to the impact of heat. Through SEM studies different types of surface morphologies, different types of pores and pore shapes in organic matter were identified. SEM studies also indicate intimate mixing of organic matter and mineral matter in shales even at submicroscopic levels. This intimate association appears to have impact on the retention of hydrocarbons by the mineral matrix during Rock Eval pyrolysis. The various micropores, microcracks, fracture traces, macropores and vacuoles may play significant role in diffusion and flow of hydrocarbons. (C) 2016 Elsevier B.V. All rights reserved.

2D Basin modelling was used to evaluate the response of source rock maturation, and of petroleum expulsion, migration, accumulation and preservation to the evolution of the southern part of the inverted Broad Fourteens Basin. Modelling results show that the temperature, maturation and petroleum generation history as well as migration characteristics of both the Jurassic oil systems and the Carboniferous gas systems vary over short distances relative to the differences in burial history of the basin. Model results indicate that no major gas accumulations are preserved in the Slochteren Formation along the cross-section at present-day. Gas accumulations are predicted in sandstone-dominated Triassic units in the southern part of the section. Present-day oil accumulations predicted in the Vlieland Sandstone Formation sealed by the Vlieland Claystone Formation (in P9 and Q1 crestal structures) are in accordance with known oil accumulations. Additional oil accumulations are predicted in the sandstone-dominated Middle Werkendam Member, and in sandstones of the Delfland Subgroup.The modelling offers an explanation for the different geochemical compositions of the accumulated oils in the P9 and Q1 areas. Modelling implies, that the oils in the Q1 oil field were sourced by remigrated oils expelled over time, from early mature to mature source rocks of the Posidonia Shale Formation. The biodegraded and water-washed nature of the Q1 oil is explained by the concentrated topography-induced groundwater flow through the Vlieland Sandstone Formation during the Late Cretaceous inversion of the basin. The oils accumulated in the P9 area were sourced from an early mature part of the Posidonia Shale Formation and were probably not affected by water washing and biodegradation because of post-inversion charging of the reservoir.

The subsurface of the onshore and offshore Netherlands has been studied extensively. In 2006 the first complete maps of the main stratigraphic horizons (down to the Permian) were published. Since then these maps were regularly updated and extended to include also the main reservoir horizons. This detailed stratigraphic information was used to quantitatively study the evolution of the Dutch subsurface by means of 3D basin modeling. At this time about 70% of the Dutch subsurface has been studied using basin modeling. Important results from these models include the heat flow evolution based on tectonic subsidence modelling, burial history, temperature evolution, maturity evolution and hydrocarbon generation of the main source-rocks as well as porosity evolution for the main reservoir horizons. These results can be used for conventional hydrocarbon exploration but also for more unconventional applications.

Pre-Westphalian layers are considered as potential source rocks in the Netherlands. However, there is little amount of information available on their maturity. 3D basin modelling is carried out on Central Onshore Netherlands to investigate the maturity of the deep Carboniferous source rocks. A detailed 3D geological model is used as input which is based on the results of the recent mapping activities in the Netherlands. Heat flow is modelled in the study area based on the tectonic evolution of the structures. The Permian uplift (Saalian event) and the associated magmatic activities are taken into account. This event has resulted in a thermal peak depicted as a peak in heat flow in the Permian. The thermal peak has influenced the maturity of the Carboniferous source rocks causing early maturity and hydrocarbon generation. Upper Carboniferous source rocks (Westphalian formations) seem to have produced some hydrocarbons in later stages which could be responsible for charging the gas fields.

The Ghadames Basin contains important oil- and gas-producing reservoirs distributed across Algeria, Tunisia, and Libya. Regional two-dimensional (2-D) modeling, using data from more than 30 wells, has been undertaken to assess the timing and distribution of hydrocarbon generation in the basin. Four potential petroleum systems have been identified: (1) a Middle-Upper Devonian (Frasnian) and Triassic (Triassic Argilo Gréseux Inférieur [TAG-I]) system in the central-western basin; (2) a Lower Silurian (Tannezuft) and Triassic (TAG-I) system to the far west; (3) a Lower Silurian (Tannezuft) and Upper Silurian (Acacus) system in the eastern and northeastern margins; and (4) a Lower Silurian (Tanezzuft) and Middle-Upper Devonian (Frasnian) system to the east-southeast. The Lower Silurian Tanezzuft source rock underwent two main phases of hydrocarbon generation. The first phase occurred during the Carboniferous, and the second started during the Cretaceous, generating most hydrocarbons in the eastern (Libyan) basin. The Frasnian shales underwent an initial, minor generative phase in the central depression during the Carboniferous. However, the main generation occurred during the Late Jurassic-Cenozoic in the western and central depression. The Frasnian shales are currently only marginally mature in the eastern part of the basin. Modeling indicates that the Alpine (Eocene) exhumation of the eastern (Libyan) basin margin had a significant control on the timing of hydrocarbon generation from the Lower Silurian source rock. The preferred burial-history model calibrates source rock maturity data by incorporating late exhumation and reduced subsidence prior to the Hercynian (Carboniferous) orogeny. As a result, the Tannezuft shales preserve their generative potential into the Mesozoic-Cenozoic, with renewed hydrocarbon generation during subsequent reburial, which can migrate to post-Hercynian. (Carboniferous) traps, hence favoring the preservation of hydrocarbon accumulations. Copyright © 2008. The American Association of Petroleum Geologists. All rights reserved.

Prospect interdependencies, if present and positively correlated, result in a higher standard deviation of the portfolio volumetric expectation curve, compared to a portfolio with independent prospects. This wider uncertainty range offers options for companies to increase the expected cumulative net present value (NPV) of the exploration portfolio. To investigate these effects on exploration portfolios, a methodology has been developed for modeling these dependencies spatially and updating them in time as new information is acquired. The methodology integrates Bayesian belief network techniques into a stochastic exploration business process simulator. Applying this methodology to the Netherlands gas portfolio clearly demonstrates an increase in both the range and expected value of NPV of the expected recoverable volume from the exploration portfolio. Proper tuning of the exploration strategy, using an efficient frontier approach, and regular updating of portfolio economic forecasts increase the probability of realizing the upside at minimum risk when compared to independent prospect portfolios. The staged decision strategy and the value of information underlying the gradual increase of expected NPV can also be calculated and visualized through decision tree analysis techniques.

The KB-5 well is located at the intersection of the geothermally active Menderes and Gediz graben systems in western Turkey. Significant volumes of “petroleum-like material” (PLM) with its associated thermal water (120 °C) erupted onto the surface during drilling from a depth of 120–132 m (i.e., from the claystone and marl-rich Early to Middle Pliocene Kolonkoya formation). The purpose of this paper is: (1) to characterize this PLM, (2) to assess the source characteristics from which the PLM was likely generated, and (3) to recognize the generation mechanism considering the geothermal-gradual versus the hydrothermal-rapid processes. Analytical organic geochemistry using thin layer chromatographic separation followed by gas chromatography–mass spectrometry (GC–MS) was carried out. The PLM is composed primarily of polar NSO compounds + asphaltenes (77%). This feature is similar to hydrothermal petroleums (e.g., Calcite Springs, Yellowstone National Park, Wyoming). The PLM shows n -alkanes ranging from n -C 19 to n -C 38 (i.e., with a maximum at n -C 30 ) but n -alkanes are depleted in n -C 19 . An absence of acyclic isoprenoids (pristane and phytane) and considerably large UCM (unresolved complex mixture) indicate that the PLM has been subjected to a moderate degree of alteration possibly by the accompanying hot geothermal waters. The source specific biomarkers [i.e., low C 29 NH/C 30 H ratio; presence of gammacerane and 18α( H )-oleanane; high C 35 /C 34 homohopane ratio and ββ-C 29 sterane concentration; n -C 28 n -C 27 n -C 29 ; C 28 27 29 ααα R steranes; %C 29 ααα R > %C 27 ααα R ] suggest that the PLM is a petroleum and was most likely generated from a Tertiary source rock with a carbonate-clay-rich lithology. The source organic matter was predominantly terrestrial and bacterial detritus deposited in relatively saline – anoxic environmental conditions. Maturity sensitive biomarker parameters (i.e., T m > T s ; C 29 sterane 20 S /(20 S + 20 R ) = 0.35; C 32 hopane 22 S /(22 S + 22 R ) = 0.57; low diasterane/regular sterane ratio) correspond to a maturity level of approximately 0.50–0.60% R o . This level of maturation could not be reached by such a young (Upper Miocene–Lower Pliocene) and shallow sedimentary column (max. 600 m) in the absence of “instantaneous” hydrothermal activity. PAHs are not detectable, but series of alkylbenzenes, alkyltoluenes, alk-1-enes and triaromatic steranes are present. The lack of organic richness and maturity in the drilled section of the KB-5 well indicates that the petroleum was generated in the deeper sections of the formation. The temperature profile of the well and composition of the hydrocarbons in the petroleum suggest that the temperature of the hydrothermal activity during hydrocarbon generation was

Four organic-rich shale units of the Proterozoic Vindhyan sedimentary succession have been scanned to reveal their origin and hydrocarbon potential. The wavy-crinkly nature of the carbonaceous laminae is suggestive of a microbial mat origin of the shales. These shales are thus different from Phanerozoic black shales which typically exhibit planar laminae. The hydrocarbon potential of the black shale units has been evaluated by Rock-Eval pyrolysis. Total organic carbon content of many of the shales exceeds 1%. The meanT max for the black shales translate to a vitrinite reflectance range of 2.05-2.40% Rm based on standard conversion techniques. These shales have reached the catagenetic stage near the beginning of anthracite formation.

The hydrocarbon systems of the Mesozoic, inverted West Netherlands Basin have been analyzed using 2-D forward modelling. Three source rocks are considered in the modelling: Lower Jurassic oil-prone shales, Westphalian gas-prone coal deposits, and Lower Namurian oil-prone shales. The Lower Namurian hydrocarbon system of the basin is discussed for the first time.According to the modelling results of the Early Jurassic oil system, the oil accumulations were filled just after the main inversion event. Their predicted locations are in agreement with exploration results. Modelling results of the Westphalian gas system, however, show smaller and larger sized accumulations at unexplored locations. The gas reservoirs were filled during the Late Jurassic-Early Cretaceous rifting phase. Results of modelling of the Lower Namurian oil system indicate that gas formed by secondary cracking of the oils can have mixed with the Westphalian coal-derived gas. Such a mixing is inferred from geochemical analyses. The existence of a Lower Namurian hydrocarbon system in the West Netherlands Basin implies that hydrocarbons are possibly trapped in the Westphalian and Namurian successions. These potential traps in the basin have not yet been explored.

L'Unité de Recherche en Pétrologie Organique est intègrée dans L'Institut des Sciences de la Terre d'Orléans - UMR6113; Microfluorimetric analyses, using new procedures have been applied on three sedimentary basins, each of them exhibiting a specific thermal history. The results have been compared to other optical and geochemical maturity parameters. It appears that the spectral fluorescence parameters cannot be used as rank parameters, because of their complex evolution with increasing diagenesis. However, they are better parameters than vitrinite reflectance for thermal maturity assessment as far as hydrocarbon generation is concerned. For instance, it is shown that different types of fluorescent materials release hydrocarbons at different levels of thermal evolution in a given series. On the other hand, alteration analyses appear to be efficient and objective tools for the punctual detection of hydrocarbons in a sample.