Shale Source Rocks Research Articles

A systematic study of internal gas generation in shale source rocks using analog experiments

A two-dimensional Hele-Shaw cell was created to study and visualize hydrocarbon source rock (i.e., shale) elastic-brittle fracture and fracture network propagation mechanisms triggered by internal gas generation and gas build up during maturation of organic components. An analog immature source rock was created using a mixture of gelatin, sugar, and live yeast in pre-determined proportions. This mixture was poured into the Hele-Shaw cell and allowed to gel. The internal gas generated as a result of sugar fermentation by yeast caused pressure build up within the gel that ultimately resulted in the activation of dissipation mechanisms such as gas diffusion and deformation of the gel matrix. These mechanisms are analogous to shale maturation and fluid generation. Image analysis was employed to study and characterize key events such as fracture nucleation, propagation, and coalescence versus time. Derivative parameters such as fracture growth rate, fracture tip pressure, and fracture spatial distribution, among others, were calculated using the image-sourced data and applying Linear Elastic Fracture Mechanics (LEFM) principles. Results showed that the experiments are repeatable within a consistent response range and additional parameters were identified to be useful input for numerical modelling, including nucleation sites, fracture merging angle, merging to nucleation ratio, and fracture connectivity. For a volume of about 100 cm3 of 11.6% wt. food-grade gelatin solution with 0.25% wt. yeast and a sugar/yeast ratio of 3, measured average total gas production was 35 cm3 (at standard conditions). On an average gelatin matrix area of 400 cm2, the average total fracture length and fracture density are 106 cm and 0.15 fractures/cm2, respectively. Average maximum calculated fracture tip pressure and maximum fracture velocity are 0.92 psi and 5.85 × 10−4 cm/s, respectively. Fracture connectivity was more frequent in the second half of the gas generation process and greater for the older and longer fractures. Average final fracture spacing was 4.42 cm. Connection angles between fractures tended to be closer to 0° than to 90°. Photoelasticity imaging techniques were applied to the experimental setup to visualize the stress field within the sample. The difference of principal stresses was estimated at 3.70 × 103 Pa for the tested material late in the maturation process. Results suggest interdependence of gas pressure, gas diffusion, and transient stress field states. The range of laboratory-scaled data are useful as benchmarking parameters for numerical modelling of source rock maturation including geomechanics.

Late gas generation potential for different types of shale source rocks: Implications from pyrolysis experiments

Gas generation from shale source rocks typically occurs via cracking of both kerogen and retained oils, such that it is difficult to predict and compare gas generation potentials of different shales because they are related not only to the kerogen type but also to the oil expulsion efficiency. In this study, five different shale kerogen samples were pyrolyzed in sealed gold tubes to investigate how kerogen type and oil expulsion efficiency affect their gas generation after oil-window maturity. The results illustrate that the maximum extractable organic matter (EOM) and gas generation potentials of different original shale kerogens (O-kerogen) in a closed system vary widely in the range of 229–790 mg/g TOCOK and 308–594 mL/g TOCOK, respectively. However, the gas yields of different residual shale kerogens (R-kerogen) with a starting equivalent vitrinite reflectance (EqVRo) value of approximately 1.22% are quite similar and vary between 131 and 145 mL/g TOCRK. Pyrolysis experiments also reveal that the late gas generation potential (EqVRo > 1.22%) of shale is mainly controlled by the amount of retained EOMs rather than kerogen type. When the shale source rocks containing types I and II kerogens have the same amount of retained EOMs, their gas generation potentials are quite similar. Under most geological conditions, the late gas generation potentials of shale source rocks, normalized to the TOC of matured shale at 1.22% EqVRo (TOCShale), vary approximately in the range of 180–300 mL/g TOCShale. To reach a gas content of 3 m3/ton shale for the present-day overmature shale gas exploration in the Lower Palaeozoic shales of South China, a conservative present-day TOC (TOCpd) value of 2.0% is proposed as a screening parameter that can eliminate the risk of insufficient gas generation potential as much as possible.

Geochemical Characterization of Two Niger Delta Crude Oils and Their Mixtures I: Bulk Properties and Aliphatic Hydrocarbon Distributions

Two crude oils from Rivers and Delta States, Niger Delta Nigeria, samples A and F respectively, and their binary mixtures at different compositions, samples B, C, D, and E, were geochemically characterized using bulk properties and aliphatic hydrocarbon distributions. Results of density and API gravity, which classified samples A, B, C, D as light oils and samples E, F as medium oils, were observed to increase and decrease with increase in the composition of oil sample F respectively. The composition of the saturates, from 68.00 to 71.10%, suggest high maturity of the oil samples which did not show a relationship to the compositional mix of the two Niger Delta crude oils. Bimodal distribution of n-alkanes in samples A and B with a slight prominence of the short chain suggest marine source with significant terrestrial input, while the prominence of the long chain n-alkanes in sample F, which suggest a terrestrial source, progressively increased in samples C, D, and E. Pr/Ph ratios from 2.37 to 2.70 suggest source rocks deposited in an oxic environment. Ratios of Pr/nC17, from 0.94 to 1.20, and Ph/nC18, from 0.39 to 0.53, suggest shale source rocks with terrestrial higher plant input. From these results, the geochemical characteristics of the individual Niger Delta crude oils were exhibited by their binary mixtures. However, density, API gravity, n-alkane distribution, Pr/nC17 and Ph/nC18 ratios were expressed relative to the compositional mix of the two Niger Delta crude oils.

Characteristics of source rocks of the Datangpo Fm, Nanhua System, at the southeastern margin of Sichuan Basin and their significance to oil and gas exploration

In recent years, much attention has been paid to the development environment, biogenetic compositions and hydrocarbon generation characteristics of ancient source rocks in the deep strata of the Sichuan Basin because oil and gas exploration extends continuously to the deep and ultra-deep strata and a giant gas field with the explored reserves of more than 1 × 1012 m3 was discovered in the Middle and Upper Proterozoic–Lower Paleozoic strata in the stable inherited paleo-uplift of the central Sichuan Basin. Based on the previous geological research results, outcrop section of the Datangpo Fm, Nanhua System, at the southeastern margin of the Sichuan Basin was observed and the samples taken from the source rocks were tested and analyzed in terms of their organic geochemistry and organic petrology. It is shown that high-quality black shale source rocks of the Datangpo Fm are developed in the tensional background at the southeastern margin of the Sichuan Basin between two glacial ages, i.e., Gucheng and Nantuo ages in the Nanhua Period. Their thickness is 16–180 m and mineral compositions are mainly clay minerals and clastic quartz. Besides, shale in the Datangpo Fm is of high-quality sapropel type source rock with high abundance at an over-mature stage, and it is characterized by low pristane/phytane ratios (0.32–0.83), low gammacerane abundance, high-abundance tricyclic terpane and higher-content C27 and C29 gonane, indicating that biogenetic compositions are mainly algae and microbes in a strong reducing environment with low salinity. It is concluded that the Datangpo Fm source rocks may be developed in the rift of Nanhua System in central Sichuan Basin. Paleo-uplifts and paleo-slopes before the Caledonian are the favorable locations for the accumulation of dispersed liquid hydrocarbons and paleo-reservoirs derived from the Datangpo Fm source rocks. In addition, scale accumulation zones of dispersed organic matter cracking gas and paleo-reservoirs originated from the Datangpo Fm source rocks may be discovered in the stable area inside the Sichuan Basin.

Assessment of Thermal Maturity Trends in Devonian–Mississippian Source Rocks Using Raman Spectroscopy: Limitations of Peak-Fitting Method

The thermal maturity of shale is often measured by vitrinite reflectance (VRo). VRo measurements for the Devonian-Mississippian black shale source rocks evaluated herein predicted thermal immaturity in areas where associated reservoir rocks are oil-producing. This limitation of the VRo method led to the current evaluation of Raman spectroscopy as a suitable alternative for developing correlations between thermal maturity and Raman spectra. In this study, Raman spectra of Devonian-Mississippian black shale source rocks were regressed against measured VRo or sample-depth. Attempts were made to develop quantitative correlations of thermal maturity. Using sample-depth as a proxy for thermal maturity is not without limitations either, as thermal maturity as a function of depth depends on thermal gradient, which can vary through time, subsidence rate, uplift, lack of uplift, and faulting. Correlations between Raman data and thermal maturity metrics were quantified by peak-fitting the spectra. Various peak-fitting procedures were evaluated to determine the effects of the number of peaks and maximum peak widths on correlations between spectral metrics and thermal maturity. Correlations between D-frequency, G-band full-width-at-half-maximum (FWHM) and band separation between the G- and D- peaks and thermal maturity provided some degree of linearity throughout most peak-fitting assessments; however, these correlations and those calculated from the G-frequency, D/G FWHM ratio, and D/G peak area ratio also revealed a strong dependence on peak-fitting processes. This dependency on spectral analysis techniques raises questions about the validity of peak-fitting, particularly given the amount of subjective analyst involvement necessary to reconstruct spectra. This research shows how user interpretation and extrapolation affected the comparability of different samples, the accuracy of generated trends, and therefore, the potential of the Raman spectral method to become an industry benchmark as a thermal maturity probe. A Raman method devoid of extensive operator interaction and data manipulation is quintessential for creating a standard method.

Petrographic and Petrophysical Characteristics of the Upper Devonian Three Forks Formation, Southern Nesson Anticline, North Dakota

Petrographic and Petrophysical Characteristics of the Upper Devonian Three Forks Formation, Southern Nesson Anticline, North Dakota

Organic geochemistry of the Silurian Tanezzuft Formation and crude oils, NC115 Concession, Murzuq Basin, southwest Libya

Thirty-six Silurian core and cuttings samples and 10 crude oil samples from Ordovician reservoirs in the NC115 Concession, Murzuq Basin, southwest Libya were studied by organic geochemical methods to determine source rock organic facies, conditions of deposition, thermal maturity and genetic relationships. The Lower Silurian Hot Shale at the base of the Tanezzuft Formation is a high-quality oil/gas-prone source rock that is currently within the early oil maturity window. The overall average TOC content of the Hot Shale is 7.2 wt% with a maximum recorded value of 20.9 wt%. By contrast, the overlying deposits of the Tanezzuft Formation have an average TOC of 0.6 wt% and a maximum value of 1.1 wt%. The organic matter in the Hot Shale consists predominantly of mixed algal and terrigenous Type-II/III kerogen, whereas the rest of the formation is dominated by terrigenous Type-III organic matter with some Type II/III kerogen. Oils from the A-, B- and H-oil fields in the NC115 Concession were almost certainly derived from marine shale source rocks that contained mixed algal and terrigenous organic input reflecting deposition under suboxic to anoxic conditions. The oils are light and sweet, and despite being similar, were almost certainly derived from different facies and maturation levels within mature source rocks. The B-oils were generated from slightly less mature source rocks than the others. Based on hierarchical cluster analysis (HCA), principal component analysis (PCA), selected source-related biomarkers and stable carbon isotope ratios, the NC115 oils can be divided into two genetic families: Family-I oils from Ordovician Mamuniyat reservoirs were probably derived from older Palaeozoic source rocks, whereas Family-II oils from Ordovician Mamuniyat–Hawaz reservoirs were probably charged from a younger Palaeozoic source of relatively high maturity. A third family appears to be a mixture of the two, but is most similar to Family-II oils. These oil families were derived from one proven mature source rock, the Early Silurian, Rhuddanian Hot Shale. There is a good correlation between the Family-II and -III oils and the Hot Shale based on carbon isotope compositions. Saturated and aromatic maturity parameters indicate that these oils were generated from a source rock of considerably higher maturity than the examined rock samples. The results imply that the oils originated from more mature source rocks outside the NC115 Concession and migrated to their current positions after generation.

Hydrocarbon migration and accumulation of the Suqiao buried-hill zone in Wen'an Slope, Jizhong Subbasin, Bohai Bay Basin, China

The hydrocarbon migration and accumulation of the Suqiao deep buried-hill zone, in the Jizhong Subbasin, the Bohai Bay Basin, eastern China, was investigated from the perspective of paleo-fluid evidence by using fluid inclusions, quantitative fluorescence techniques (QGF), total scanning fluorescence method (TSF) and organic geochemical analysis. Results show that the current condensate oil-gas reservoirs in the study area once were paleo-oil reservoirs. In addition, the reservoirs have experienced at least two stages of hydrocarbon charge from different sources and/or maturities. During the deposition of the Oligocene Dongying Formation (Ed), the deep Ordovician reservoirs were first charged by mature oils sourced from the lacustrine shale source rocks in the fourth member of Shahejie and Kongdian Formations (Es4+Ek), and then adjusted at the end of Ed period subsequently by virtue of the tectonic movement. Since the deposition of the Neogene Minghuazhen Formation (Nm), the reservoirs were mainly charged by the gas that consisted of moderate to high-maturity condensate and wet gas sourced from the Es4+Ek lacustrine shale source rocks and mature coal-derived gas sourced from the Carboniferous-Permian (C-P) coal-bearing source rocks. Meanwhile, the early charged oil was subjected to gas flushing and deasphalting by the late intrusion of gas. The widely distributed hydrocarbon inclusions, the higher QGF Index, and FOI (the frequency of oil inclusions) values in both gas-oil and water zone, are indicative of early oil charge. In addition, combined with the homogenization temperatures of the fluid inclusions (<160 °C) and the existence of solid-bitumen bearing inclusions, significant loss of the n-alkanes with low carbon numbers, enrichments of heavier components in crude oils, and the precipitation of asphaltene in the residual pores suggest that gas flushing may have played an important role in the reservoir formation.

The petroleum system of the Tenere Basin: oil geochemistry from the SH-1 wildcat well in eastern Niger

The SH-1 wildcat well, firstly encountering oil, proved the existence of a working petroleum system in the Tenere Basin, but the origin of oil and its generation history is not fully understood. In this regard, one crude oil and nine Upper Cretaceous source rock samples from the SH-1 wildcat well in the Tenere Basin were characterized by a variety of biomarker parameters and stable carbon isotopic composition. The oil from the Tenere Basin displays a low pristine/phytane (Pr/Ph) ratio, low C 29 /C 30 and C 35 /C 34 hopane ratios, low C 22 /C 21 and high C 24 /C 23 tricyclic terpane ratios, and high gammacerane index (gammacerane/C 30 hopane), suggesting shale source rocks deposited under an anoxic and relatively high-salinity environment. Relatively high C 29 sterane concentrations, a low value of the regular steranes/17 α (H)-hopanes ratio and a canonical variable from stable carbon isotopic composition larger than 0.47 indicate that the oil is mainly derived from terrestrial higher plants. Both aromatic maturity parameters and sterane isomerization parameters suggest that the oil was generated from an early mature source rock. Correlation between oils from the Tenere Basin and those from the Termit Basin confirms that these oils belong to the same genetic family. The oil–source rock correlation suggests that the oil from the Tenere Basin originated from the Upper Cretaceous marine source rocks, and the Yogou Formation can be considered as effective source potential.

Geochemical methods for prediction and assessment of shale oil resources (case study of the Bazhenov Formation)

The paper presents approaches to characterization of shale source rocks using geochemical data for the case of the Bazhenov petroleum system in West Siberia. Regional patterns of oil distribution in the Bazhenov shale are shown to depend on their original total organic carbon (TOC) content and thermal maturity. The existing thermal maturity model for the Bazhenov Formation based on vitrinite reflectance (R°t) of nearby beds has been updated using parameters measured by Rock-Eval pyrolysis (Tmax, HI, PC, and RC) for the shale itself. The results were used to quantify hydrocarbon resources in different maturity zones. The relationship between TOC and the presence of para-autochthonous oil found for logged zones in the Bazhenov section allows allocating and quantifying oil resources in unlogged beds.

Mineral carbon MinC(%) from Rock-Eval analysis as a reliable and cost-effective measurement of carbonate contents in shale source and reservoir rocks

The abundance of carbonate minerals in rocks is an important element for petroleum geochemists, geologists and engineers to consider during hydrocarbon exploration and production. Carbonate minerals can be related to the depositional environments of the source rocks and hence the type of organic matter that can be subsequently modified through diagenetic processes. The total carbonate content in shales can also be used to deduce their fracability as reservoir rock for shale gas/oil extraction. At present, mineralogical analysis by X-ray diffraction (XRD) is the most widely used technique in the oil and gas-related petrophysical and geochemical laboratories for identifying and quantifying carbonate minerals in rock samples. In contrast, the use of the total mineral carbon content parameter MinC (%) from Rock-Eval analysis has been limited despite (1) the parameter's effectiveness as demonstrated through instrument and methodology development; and (2) the presence of a large volume of Rock-Eval results due to its widespread use in the oil and gas industry.In this study, we acquired XRD and Rock-Eval analytical results on over nine hundred rock samples ranging from Ordovician to Cretaceous age from four petroleum sedimentary basins in Canada. Least-squares regression analyses produce empirical equations with R2 values greater than 0.92 for the correlations between XRD total carbonate contents and the Rock-Eval MinC (%) values of six different suites of samples. This indicates that the MinC (%) values generated by Rock-Eval 6 and other instruments of similar capability can be used with confidence for estimating the amounts of total carbonates in sedimentary rock samples. While the correlation between the two types of carbonate content measurements is geology-specific, a global linear regression model (R2 of 0.97) based on the large combined data set has been proposed for approximating the total carbonate abundances based on Rock-Eval MinC (%) values.

3D basin and petroleum system modelling of the NW German North Sea (Entenschnabel)

Abstract 3D basin and petroleum system modelling covering the NW German North Sea (Entenschnabel) was performed to reconstruct the thermal history, maturity and petroleum generation of three potential source rocks, namely the Namurian–Visean coals, the Lower Jurassic Posidonia Shale and the Upper Jurassic Hot Shale. Modelling results indicate that the NW study area did not experience the Late Jurassic heat flow peak of rifting as in the Central Graben. Therefore, two distinct heat flow histories are needed since the Late Jurassic to achieve a match between measured and calculated vitrinite reflection data. The Namurian–Visean source rocks entered the early oil window during the Late Carboniferous, and reached an overmature state in the Central Graben during the Late Jurassic. The oil-prone Posidonia Shale entered the main oil window in the Central Graben during the Late Jurassic. The deepest part of the Posidonia Shale reached the gas window in the Early Cretaceous, showing maximum transformation ratios of 97% at the present day. The Hot Shale source rock exhibits transformation ratios of up to 78% within the NW Entenschnabel and up to 20% within the Central Graben area. The existing gas field (A6-A) and oil shows in Chalk sediments of the Central Graben can be explained by our model.

Organic geochemical characteristics of oils from the offshore Jiza-Qamar Basin, Eastern Yemen: New insight on coal/coaly shale source rocks

Coals, coaly shales and oil show samples from Late Cretaceous sections in the offshore Jiza-Qamar Basin (Yemen) were analysed using organic geochemical analyses to investigate the source of organic matter input and the genetic link between oils and potential source rocks in the basin. The coals and coaly shales have high TOC contents between 6.90 and 77.62wt% and Hydrogen Index (HI) values are largely above 300mg HC/g TOC, indicating that the Late Cretaceous coaly shales and coals as expected are organically rich, and predominantly contain Type III-II kerogens.The oil shows are classified as paraffinic–naphthenic–aromatic (P–N–A) oil with high wax contents, suggesting that the oils were generated from coal and coaly source rocks that were deposited in a deltaic–coastal environment. This is supported by bulk geochemical characteristics and biomarker compositions. A variety of biomarkers n-alkanes, regular isoprenoids, terpanes and steranes indicate that the oil shows were derived predominantly from source rock containing higher plant derived organic matter and were deposited in fluvial to deltaic environments under relatively oxic conditions. The biomarker characteristics and stable isotope compositions of the oils are similar to those of the Late Cretaceous coal and coaly shale rocks. The new data presented in this paper suggests genetic link between oil shows and coal/coaly shale rocks in the offshore Jiza-Qamar Basin and provides new evidence for the oil generative potential of the Cretaceous coals and coaly shales in the basin.

Upper Jurassic–lowermost Cretaceous marine shale source rocks (Farsund Formation), North Sea: Kerogen composition and quality and the adverse effect of oil-based mud contamination on organic geochemical analyses

The Jude-1 well is located in the central part of the Danish Central Graben, North Sea, and was drilled into immature black shales of the Upper Jurassic–lowermost Farsund Formation, a world-class marine source rock. The well was drilled with oil-based drilling mud (OBM). The lithofacies consists of argillaceous shale, calcareous shale and dolomite stringers as confirmed by cuttings and core. A core was taken in the upper part of the formation at the beginning of a ‘hot’ argillaceous shale interval characterized by elevated TOC and HI values. Cuttings and core samples were investigated to unravel kerogen composition, source rock quality and the contamination effect of OBM on organic geochemical analyses. The organic facies of the source rocks corresponds to Type II kerogen or Organofacies B (sensu Pepper and Corvi, 1995). Considerable fluctuations in HI values through the Farsund Formation reflect pronounced variations in source rock quality, although a faint lamination of the shales and overall high TOC contents testify to prevailing oxygen-deficient depositional conditions preventing significant bioturbation and reworking of the sediment and organic matter. Petrography of core samples reveals a relatively homogenous sapropelic kerogen composition dominated by a groundmass of yellowish fluorescing amorphous organic matter and liptodetrinite intimately associated with the mineral matrix. Telalginite is less abundant, but Tasmanites- and in particular Leiosphaerida-type telalginites were observed. Minor but varying amounts of detrital terrigenous macerals suggest a considerable distance to land areas and thus limited supply of land plant-derived organic matter. The argillaceous shale lithofacies generally is more oil-prone and organic-rich than the more gas-prone calcareous shale facies. The uppermost section includes the ‘hot’ argillaceous shales, which together with two deeper argillaceous shale intervals are highly organic-rich and oil-prone. Average TOC of the ‘hot’ argillaceous shales is ~7wt% and HI reaches >500mgHC/gTOC. The total Ultimate Expulsion Potential (UEP) of the over 853m (2799ft) thick Farsund Formation is ~142mmboe/km2. Results from non-contaminated samples are thus consistent with the Farsund Formation being a world-class highly oil-prone marine source rock. The predicted oil composition corresponds to ‘paraffinic low wax oils’. The adverse effect of OBM contamination on geochemical analyses is demonstrated by Rock-Eval data and measured bulk kinetics of contaminated core samples. The measured kinetics has a considerable proportion of low activation energies related to OBM contamination which is also supported by high Production Indices. Further, gas chromatograms of the saturated fraction of extracts from contaminated cores clearly show evidence of OBM in the nC11–nC14 range. Rock-Eval S2 peaks have a ‘shoulder’ showing that the low Ea-peaks result from carry over from the S1 peak, caused by the OBM contamination. As a consequence Hydrogen Index values are increased.

MIGRATED PETROLEUM IN OUTCROPPING MESOZOIC SEDIMENTARY ROCKS IN SPITSBERGEN: ORGANIC GEOCHEMICAL CHARACTERIZATION AND IMPLICATIONS FOR REGIONAL EXPLORATION

The presence of migrated petroleum in outcropping rocks on Spitsbergen (Svalbard archipelago) has been known for several decades but the petroleum has not been evaluated by modern geochemical methods. This paper presents detailed organic geochemical observations on bitumen in outcrop samples from central and eastern Spitsbergen. The samples comprise sandstones from the Lower Cretaceous Carolinefjellet Formation, the Upper Triassic – Middle Jurassic Wilhelmøya Subgroup and the Upper Triassic De Geerdalen Formation; a limestone from the De Geerdalen Formation; and carbonates from the Middle Jurassic – Lower Cretaceous Agardhfjellet Formation. In addition a palaeo‐seepage oil was sampled from a vug in the Middle Triassic Botneheia Formation. This data is integrated with the results of analyses of C1–C4 hydrocarbon fluid inclusions trapped in quartz and calcite cements in these samples.Organic geochemical data suggest that the petroleum present in the samples analysed can be divided into two compositional groups (Group I and Group II). Group I petroleums have distinctive biomarker characteristics including Pr/Ph ratios of about 1.3–1.5, high tricyclic terpanes relative to pentacyclic terpanes, and relatively high methyl‐dibenzothiophenes compared to methyl‐phenanthrenes. By contrast Group II petroleums have low tricyclic terpanes relative to pentacyclic terpanes and low methyl‐dibenzothiophenes compared to methyl‐phenanthrenes, and most Pr/Ph ratios range from 1.90 to 2.57. The petroleum in both groups was derived from marine shale source rocks deposited in proximal to open marine settings.Group I petroleums, present in the sandstones of the Wilhelmøya Subgroup and the De Geerdalen Formation and as a palaeo‐seepage oil in the vug in the Botneheia Formation, are likely to have been sourced from the Middle Triassic Botneheia Formation. Group II petroleums, found in the sandstone of the Carolinefjellet Formation, the limestone from the De Geerdalen Formation and in carbonates of the Agardhfjellet Formation, are inferred to have been generated from the Jurassic‐Cretaceous Agardhfjellet Formation.The analysis of biomarker and aromatic hydrocarbons in the petroleums indicate three relative maturation levels, equivalent to expulsion at vitrinite reflectances of about 0.7–0.8%Rc, 0.8–0.9%Rc and 1.0–1.6%Rc. On average, Triassic host rocks contain petroleum of higher maturity compared to the Jurassic and Cretaceous host rocks.The fluid inclusion data suggest that gaseous hydrocarbons from the sandstones of the Wilhelmøya Subgroup are thermogenic, and are of similar maturity to the petroleum in extracts from these sandstones, suggesting that the gas was generated together with oil in the oil window. By contrast the inclusion gases from carbonate rocks analysed have a mixed (thermogenic / biogenic) origin.The outcropping rocks in which these oils occur are analogous to offshore reservoirs on the Norwegian Continental Shelf. The study may therefore improve our understanding of the subsurface offshore petroleum systems in the Barents Sea and possibly also in other circum‐Arctic basins.

Geochemical composition of oils from the Gifhorn Trough and Lower Saxony Basin in comparison to Posidonia Shale source rocks from the Hils Syncline, Northern Germany

Geochemical composition of oils from the Gifhorn Trough and Lower Saxony Basin in comparison to Posidonia Shale source rocks from the Hils Syncline, Northern Germany

Tracing the Impact of Fluid Retention on Bulk Petroleum Properties Using Nitrogen-Containing Compounds

Predicting gas-to-oil ratio (GOR) and bulk petroleum properties is of paramount concern when developing production strategies for unconventional resource plays. Subtle changes in bulk fluid composition can result in large differences in phase envelope geometry and predicted fluid types, which can cause unfavorable pressure drawdown during production. Here we present new insights into the thermal evolution of petroleum compositions in conventional and unconventional reservoirs, focusing on polar compounds, i.e., nitrogen-, sulfur-, and oxygen-containing (NSO) compounds. These compounds feature functional groups that strongly influence the sorption, solubility, and partitioning behavior of petroleum constituents in unconventional shale systems. Fourier transform ion cyclotron resonance mass spectrometry (FT-ICR MS) is a powerful tool to rapidly characterize NSO-compounds in complex mixtures and was used to compare the polar compounds in (1) extracts of six Posidonia Shale source rock samples with maturity l...

Manganese Deposits of Africa

Africa hosts just over 80 percent (%) of the world's known land-based ore resources of manganese metal and produced some 41.1% of the 18 million tonnes (Mt) of manganese metal in ores, that was mined during 2014. The deposits are mainly of sedimentary and supergene origin comprising four major types, namely banded iron formation (BIF)-hosted, black shale-hosted, oolitic and supergene/karst-hosted deposits. The BIF-hosted Kalahari Manganese Field (KMF) is by far the largest of these deposits holding some 4,200 Mt of manganese metal that represents about 77% of the world's known land-based resource. Other major deposits are present in the Francevillian of Gabon, represented by high-grade supergene manganese oxide ores derived from weathering of rhodochrosite-bearing black shale source rock, and manganese carbonates interbedded with black shale and greywackes associated with volcanicdominated orogenic belts in the Birimian of West Africa and Lukoshi Complex at Kisenge in the Democratic Republic of the Congo (DRC). High-grade supergene manganese oxide ores cap the manganese carbonate beds. All these major ore deposits formed in the interval 2.0-2.2 Ga. Additional deposits that contain only relatively small resources but that hold important scientific information about the Earth's history include the ~ 2.4 Ga BIF-hosted Rooinekke deposit of the Transvaal Supergroup, which formed prior to the ~ 2.32 Ga Great Oxidation Event (GOE), karst-hosted deposits of the Postmasburg area that formed along a 2.0 Ga palaeoweathering profile below red beds of the Gamagara/Mapedi succession in South Africa, the ~1.9 Ga Tolwe deposit that represents the oldest known example of oolitic manganese ore in the world and the BIF-hosted Otjosondu deposit in Namibia, related to the Neoproterozoic Sturtian Snowball Earth Event (an extremely cold period of time in geologic history when Earth was covered by a virtual global ice cap). The manganese carbonates present in most of these deposits are all highly enriched in light organic carbon isotopes indicating that they were derived from reduction of original manganese oxide precipitates by organic carbon during diagenesis. This implies that the water columns from which the sedimentary manganese beds originally precipitated, as well as the floors of the depositories, were oxygenated. Post Archaean Australian Shale (PAAS)-normalized cerium (Ce) anomalies in Rare Earth Element (REE) data, support the presence of oxic conditions in the basins. It is thus not surprising that all the major 2.0-2.2 Ga deposits formed after the GOE. In this regard the relatively small BIF-hosted Rooinekke manganese deposit is very significant in that it formed prior to the GOE suggesting that at least some free oxygen was present in ocean basins before that time. There also appears to have been a major tectonosedimentary control on the distribution of the major 2.0- 2.2 Ga deposits. All of them, including the KMF, apparently formed in back-arc basinal settings immediately prior to amalgamation of cratonic blocks along Eburnian orogenic belts and formation of the supercontinent Columbia.

The Silurian Qusaiba Hot Shales of Saudi Arabia: An integrated assessment of thermal maturity

The Lower Silurian Qusaiba Hot Shales (QHS) are proven source rocks for oil within the Paleozoic, and possibly some of the Mesozoic, reservoirs in Saudi Arabia. Moreover, these shales have oil shale potential where they are immature and shallow enough for mining, as well as unconventional shale oil and shale gas potential, in areas where they are within oil-maturity and gas-maturity levels, respectively. The QHS were deposited in relatively shallow marine environments under anoxic water conditions, resulting in accumulation of amorphous kerogen, organic-walled graptolites and acritarchs. Across the Arabian Basin, organic matter quality does not show much variation for the QHS, but the maturity varies greatly as a result of varying burial history.Thermal maturity assessment of shale source rocks that lack vitrinite, such as the Qusaiba Hot shales, continues to be challenging, especially where conflicting measurements are obtained from different sources.This paper presents an integrated assessment of QHS thermal maturity parameters, based on cores from 13 carefully selected boreholes that – based on regional basin models – are believed to cover a wide maturity range (ca. 0.5 to 2.0% Ro). We conducted some analyses on kerogen (maceral petrography, graptolite reflectance, UV-fluorescence, whole rock pyrolysis, Raman spectroscopy of graptolite) and other analyses on bitumen extracts (GC and GC–MS of saturate and aromatic fractions, and FTIR spectroscopy of the asphaltene fraction). We show that using many thermal maturity parameters reduces uncertainty significantly, and we therefore recommend that graptolite reflectance analyses should be conducted in support of other maturity indicators. Proper reflectivity measurements of the graptolites set the reference for comparison of other maturity parameters obtained from petrographic, geochemical, and spectroscopic techniques. Our work provides a template by which Qusaiba thermal maturity can be more accurately estimated when only a limited set of maturity parameters is available.

Petroleum assessment of Berkine–Ghadames Basin, southern Tunisia

Hydrocarbon exploration in the Berkine–Ghadames Basin in southern Tunisia has generally followed global economic trends. In recent years, improvements in seismic data acquisition combined with experience gained in log interpretation in low-resistivity reservoirs have resulted in oil and gas discoveries in the Upper Silurian Acacus Formation, enriching the hydrocarbon potential of the Berkine–Ghadames Basin in southern Tunisia. Presently, the Tunisian daily oil production is approximately 43,000 bbl, about half of which comes from the fields located in southern Tunisia and is produced from the Acacus Formation. The Berkine–Ghadames Basin is an intracratonic basin formed during the Pan-African Orogeny. It covers an area of approximately 350,000 km2 (135,135 mi2) and extends into Algeria, Libya, and Tunisia. The sedimentary section within the basin ranges from Cambrian to present and is approximately 7000 m (23,000 ft) thick in the depocenter. The basin has experienced several tectonic events, which have modified its architecture and affected the petroleum systems and hydrocarbon pathways. In this study, the main elements of the petroleum geology systems are described. With the geochemical modeling results, the petroleum potential, hydrocarbon generation, expulsion time, and quantity of hydrocarbon are assessed. The main petroleum systems are also defined. They are represented by the Silurian Tannezuft hot shale source rock with Ordovician Djeffara and Silurian Acacus reservoirs, by Silurian Tannezuft hot shale with Kirchaou reservoirs, and by the Devonian Aouinette Ouinine Formation Member III source rock with Kirchaou reservoirs. The hydrocarbon traps in the area are mainly structural types. The study describes and emphasizes the hydrocarbon migration pathway mechanism from source rocks to traps. To predict and derisk future drilling locations, fairway maps are generated for the three plays: Ordovician, Silurian, and Triassic. Although the paper focuses on southern Tunisia, an attempt is made to introduce Libyan and Algerian knowledge to evaluate the basin in a regional context.