Search Results (82)

The present study focused on the Upper Cretaceous to Middle Miocene sequence in the Central Gulf of Suez, Egypt. The Upper Cretaceous to Middle Miocene sequence in the October field is thick and deeply buried, consisting mainly of brown limestone, chalk limestone, and reefal limestone intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC), Rock-Eval pyrolysis, visual kerogen examination, vitrinite reflectance (%Ro), and bottom-hole temperature measurements. The main objective of this study is to delineate the source rock characteristics of these strata regarding organic richness, thermal maturity, kerogen type, timing of hydrocarbon transformation and generation. The Upper Cretaceous Brown Limestone Formation is represented by 135 samples from four wells and is considered to be a fair to excellent source rock, primarily containing type I and II kerogen. It is immature to early mature, generating oil with a low to intermediate level of hydrocarbon conversion. The Eocene Thebes Formation is represented by 105 samples from six wells and is considered to be a good to fair oil source rock with some potential for gas, primarily containing type II and II/III kerogen. Most samples are immature with a low level of hydrocarbon conversion while few are mature having an intermediate degree of hydrocarbon conversion. The Middle Miocene Lower Rudeis Formation is represented by 8 samples from two wells and considered to be a fair but immature source rock, primarily containing type III kerogen with a low level of conversion representing a potential source for gas. The Middle Miocene Belayim Formation is represented by 29 samples from three wells and is considered to be a poor to good source rock, primarily containing kerogen type II and III. Most samples are immature with a low level of hydrocarbon conversion while few are mature having an intermediate degree of hydrocarbon conversion. 1D basin model A-5 well shows that the Upper Cretaceous Brown Limestone source rock entered the early oil window at 39 Ma, progressed to the main oil window by 13 Ma, and remains in this stage today. The Eocene Thebes source rock began generating hydrocarbons at 21.3 Ma, advanced to the main oil window at 11 Ma, and has been in the late oil window since 1.6 Ma. The Middle Miocene Lower Rudeis source rock entered the early oil window at 12.6 Ma, transitioned to the main oil window at 5.7 Ma, where it remains active. In contrast, the Middle Miocene Belayim source rock has not yet reached the early oil window and remains immature, with values ranging from 0.00 to 0.55 % Ro. The transformation ratio plot shows that the Brown Limestone Formation began transforming into the Upper Cretaceous (73 Ma), reaching 29.84% by the Miocene (14.3 Ma). The Thebes Formation initiated transformation in the Late Eocene (52.3 Ma) and reached 6.42% by 16.4 Ma. The Lower Rudeis Formation began in the Middle Miocene (18.7 Ma), reaching 3.59% by 9.2 Ma. The Belayim Formation started its transformation at 11.2 Ma, reaching 0.63% by 6.8 Ma. Full article

Gypsum and salt rocks have been proven to act as seals for abundant oil and gas reserves on a global scale, with significant potential for hydrocarbon preservation and evolution. Notably, the sedimentary dynamics of non-evaporitic gypsum in terrestrial half-graben basins remain underexplored, particularly regarding its genetic link to hydrocarbon accumulation in interbedded mudstones. This study is based on the Zhanhua Sag, in which thick-layered gypsum rocks with dark mudstone are deposited. The gypsum crystals show the intermittent deposition characteristics. The cumulative thickness of the gypsum-containing section reaches a maximum of over 110 m. The spatial distribution of gypsum thickness correlates strongly with the location of deep-seated faults. The strontium and sulfur isotopes of gypsum indicate deep hydrothermal fluids as mineral sources, and negative oxygen isotope excursions also suggest that gypsum layers precipitated in situ from hot brine. Total organic carbon and Rock-Eval data indicate that the deep-lake gypsum rock system has excellent hydrocarbon potential, especially in the mudstone interlayers. This study developed a depositional model of deep-lake gypsum rocks with thermal brine genesis in half-graben basins. The gypsum-bearing system is rich in mudstone interlayers. These gypsum–mudstone interbeds represent promising targets for shale oil exploration after the initial breakthrough during the extraction process. These insights provide a theoretical framework for understanding gypsum-related petroleum systems in half-graben basins across the globe, offering guidance for hydrocarbon exploration in analogous sedimentary environments. Full article

The pathways and mechanisms of primary hydrocarbon migration, which are still not well understood, are of great significance for evaluating both conventional and unconventional oil and gas resources, understanding the mechanisms of shale oil retention, and predicting sweet spots. To investigate the petrography, geochemistry, and pore systems of organic-rich mudstones and organic-lean sand-silt intervals in core samples from the Yanchang shale in the Ordos Basin, China, we conducted thin-section observation, X-ray diffraction, Rock-Eval pyrolysis, field emission scanning electron microscopy (FE-SEM), and porosity analysis. Sand-silt intervals are heterogeneously developed within the Yanchang shale. The petrology, mineral composition, geochemistry, type, and content of solid organic matter as well as the pore type, pore size, and porosity of these intervals differ significantly from those of mudstones. Compared with mudstones, sand-silt intervals typically have coarser detrital grain sizes, higher contents of quartz, feldspar, and migrated solid bitumen (MSB), larger pore sizes, higher porosity, and higher oil saturation index (OSI). In contrast, they have lower contents of clay minerals, total organic carbon (TOC), free liquid hydrocarbons (S₁), and total residual hydrocarbons (S₂). The sand-silt intervals in the Yanchang shale serve as both pathways for hydrocarbon primary migration and “micro reservoirs” for hydrocarbon storage. The interconnected inorganic and organic pore systems, organic matter networks, fractures, and sand-silt intervals form the hydrocarbons’ primary migration pathways within the Yanchang shale. A model for the primary migration of hydrocarbons within the Yanchang shale is proposed. Full article

The Central Depression of the Junggar Basin relies heavily on Permian lacustrine mudstone for deep-seated hydrocarbon sealing. This research investigated how the fluorescence parameters of caprock samples responded to the leakage of palaeo-oil zones based on measurements from SEM, Rock-Eval, and X-ray diffraction analysis. First, two sets of control experiments were conducted to establish the proper grain-size range of 100–140 mesh for testing caprock samples in the research area using quantitative fluorescence technology. Subsequently, based on the examination of the rock pyrolysis parameters and the fluorescence parameters against TOC values, the conjecture was formed that the quantitative fluorescence technology test results were mostly unaffected by the primary hydrocarbons. Lastly, four fluorescence parameters were used to assess seal integrity: quantitative grain fluorescence intensity of the extract (QGF E intensity, the meaning of QGF is the same in this study), QGF spectral peaks (QGF λmax), the ratio of QGF intensity to fluorescence intensity at 300 nm on the QGF spectrum (QGF index), and total scanning fluorescence spectral ratio R₁ (TSF R₁). The Permian caprock can effectively seal hydrocarbons as evidenced by the decrease of QGF E intensity and QGF index values with depth. When hydraulic fracturing causes caprock failure, it can lead to complete leakage of hydrocarbons from the palaeo-oil zones. As the depth becomes shallower, the QGF E intensity value increases, the QGF index value decreases. Due to the differences in the migration pathways of hydrocarbons in the caprock, those leaked from the Permian palaeo-oil zone into the well PD1 caprock are mainly condensate and light–normal crude oil, while the hydrocarbons from the Carboniferous palaeo-oil zone into the well MS1 caprock consist predominantly of light–normal crude oil and medium–heavy crude oil. Full article

The most organic-rich shales are defined in the Dobele Fm. of the Aeronian Stage of about 10 m thick in west Lithuania. This particular layer is documented in the whole Baltic Basin. Compatible shales are widely distributed in other basins referred to as similar Silurian “hot” shales. The average TOC was estimated at 6.67 wt.% (good and excellent source rock). The thermal maturity of shales was evaluated through organic geochemical techniques, including TOC determination, Rock–Eval pyrolysis, and organic petrography studies. The thermal maturity varies from T_max = 431 °C and eq.VR_o = 0.65% (early oil) to T_max = 468 °C and VR_o = 1.38% (locally up to 1.94%) (late oil and wet to dry gas generation). It is notable, most of the study area is confined to regional-scale West Lithuanian Geothermal Anomaly. Most of the geothermal features, both palaeo- and recent, recorded in lateral variation in thermal maturity of shales unravel persistence of heat flow. Locally, the Variscan tectonic activity was imprinted in thermal maturity of organic matter-rich shales (Žemaičių Naumiestis anomaly). Full article

The complex interaction of hydrothermal fluids and carbonate rocks is recognized to promote significant impacts on petroleum systems, reservoir porosity, and potential. The objective of this study is to investigate the fluid phases entrapped in the mineral phases of the Barra Velha Formation (Santos Basin), including their petrographic paragenetic relationships, relative timing, temperatures of migration events, and maximum temperature reached by the sedimentary section. The petrographic descriptions (387), Rock-Eval pyrolysis (107), fluid inclusion petrography (14), and microthermometry (428) were performed on core and sidewall samples from two wells from one field of the Santos Basin. Hydrocarbon source intervals were primarily identified in lithologies with high argillaceous content. Chert samples still retain some organic remnants indicative of their original composition prior to extensive silicification. Redeposited intraclastic rocks exhibit the lowest organic content and oil potential. A hydrothermal petroleum system is identified by fluids consisting in gas condensate, light to heavy undersaturated oil, occasionally accompanied by aqueous fluids influenced by juvenile and evaporitic sources, and localized flash vaporization events. These hydrothermal fluids promoted silicification and dolomitization, intense brecciation, and lead to enhanced porosity in different compartments of the reservoir. The relative ordering of paleo-hydrothermal oils and the main oil migration and accumulation events has improved our understanding of the petroleum systems in the basin. This contribution is significant for future regional research on the evolution of fluid systems and their implications for carbonate reservoirs. Full article

The Lucaogou Formation in the Santanghu Basin is notable for its abundance of oxygen-containing compounds, especially the γ-alkylbutyrolactone series (GBLs), which were detected for the first time in the shales. However, the origin and geological significance of these compounds in sediment are unclear. In this study, source rock samples from the Lucaogou Formation in the Santanghu Basin were collected and classified into two categories (high-GBL content (Group H); low-GBL content (Group L)) based on gas chromatography–mass spectrometry. The biomarker results indicate that the medium-chain n-alkanes in Group H are more enriched. In addition, the source rocks of both Group H and Group L were formed in a reducing and salinized sedimentary environment. The Rock-Eval pyrolysis results indicate that Group H has high organic matter abundance and organic matter types of I–II₁, illustrating the contribution of submerged algae, whereas Group L has low organic matter abundance and organic matter types II₂–III. Based on the above results, the GBLs exhibit typical biogenic characteristics and is likely to originate from specific submerged algae. Thermal simulation experiments further confirm that Group H has a greater hydrocarbon generation. Combined with gas isotope evidence, these findings show that the high abundance of GBLs compounds is effectively preserved during the formation of excellent source rocks and promotes the formation of petroleum. Full article

The oil content of shale oil reservoirs is a key parameter for reserve evaluation and “sweet spot” selection. However, discrepancies in the oil contents obtained by different methods have led to considerable disparities in the selection of exploration well locations and development strategies for shale oil. This study focuses on low to moderately mature sealed coring samples from the Dongying Depression in the Bohai Bay Basin. Three methods—NMR, Dean–Stark, and Rock-Eval—were employed to measure the oil content of shale. The results indicate that the oil content obtained by NMR is the highest, followed by the Dean–Stark distillation extraction method, while the pyrolysis method yields the lowest value. The study found that (1) the efficiency of the solvent extraction effect on moderately to low-mature shale is low since the occurrence of numerous closed pores leads to a lower yield when using the Dean–Stark method. (2) The exposure of shale samples to the air, sample crushing, and lag time for temperature increase cause a significant loss of light hydrocarbon components, resulting in the lowest oil content when measured by the Rock-Eval method. The NMR method, with its advantages of a short analysis time and non-destructive nature, appears to be the most advantageous method for shale oil content evaluation. Full article

Shale oil and gas resources have become an alternative energy source and are crucial in the field of sustainable oil and gas exploration. In the Junggar Basin, the Permian is not only the most significant source rock, but also an important field in shale oil and gas exploration. However, there are significant differences in the effectiveness of source rocks in different layers. During the Permian, the Bogda region effectively recorded the transition from marine environments in the Early Permian to terrestrial environments in the Late Permian, providing a viable opportunity for studying the Permian source rock of the Junggar Basin. We conducted an analysis of the total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), and biomarker compounds of Permian source rocks around the Bogda Mountain. The results indicate that the Lower Permian strata were primarily deposited in a moderately reducing marine environment, with the main organic matter sourced from planktonic organisms. These strata are currently in a high to over-mature stage, evaluated as medium-quality source rocks, and may have already generated and expelled substantial quantities of oil and gas, making the Lower Permian hydrocarbon resources within the basin a noteworthy target for deep condensate oil and gas exploration in adjacent depressions. The Middle Permian Wulabo and Jingjingzigou formations were deposited in a moderately oxidizing marine–continental transitional environment with significant terrestrial organic input. The kerogen type is predominantly Type III, and these formations are presently in the mature to over-mature stage with low organic abundance and poor hydrocarbon generation potential. The Middle Permian Lucaogou Formation was deposited in a moderately reducing saline lacustrine environment, with algae and planktonic organisms as the primary sources of organic matter. The kerogen types are mainly Type I and II₁, and it is currently within the oil-generation window. It is characterized by high organic abundance and evaluated as good to excellent source rocks, possessing substantial potential for shale oil exploration. The Upper Permian Wutonggou Formation was primarily deposited in a highly oxidizing continental environment with significant terrestrial input. The primary organic source comprises higher plants, resulting in Type III kerogen. These strata exhibit low organic abundance, are currently in the immature to mature stage, and are evaluated as poor source rocks with limited exploration potential. The information presented in this paper has important theoretical significance and practical value for oil and gas exploration and development in the Junggar Basin. Full article

To reveal the shale oil occurrence state and its controlling factors of the Jurassic Lianggaoshan Formation in the Sichuan Basin, experimental analyses, including total organic content, X-ray diffraction, low-temperature nitrogen adsorption-desorption, nuclear magnetic resonance, conventional, and multistage rock-eval, were conducted on the shale samples. The shale oil occurrence state, the amount/proportion of adsorbed/free oil, and their control factors were clarified. Moreover, the classification evaluation standard of shale oil resources was then determined. The results show that the selected shales are characterized by large oil contents. Total oil ranges from 0.08 mg/g to 10.06 mg/g (mean 2.82 mg/g). Adsorbed oil is between 0.03 mg/g and 5.66 mg/g (1.64 mg/g), while free oil spans from 0.05 mg/g to 4.94 mg/g (1.21 mg/g). The higher the total oil content, the higher the free oil content, indicating that the free oil sweet spot corresponds to the shale oil resource sweet spot. Shale oil is mainly adsorbed in organic matter; the larger TOC content results in the higher adsorbed oil content. Residual shale oil primarily occurs in pores less than 100 nm in diameter, and a higher pore volume corresponds to a higher total oil content. The shale oil enrichment resources refer to the shale with the TOC > 1.5%, S₁ > 1.5 mg/g, and S₁/TOC > 45 mg/g. This study is helpful for the prediction of shale oil resources and optimizing sweet spots in the Jurassic Lianggaoshan Formation of the Sichuan Basin. Full article

The Permian Qipan Formation (P_1-2q) is the aim horizon for hydrocarbon source rocks in the piedmont area of southwestern Tarim Basin. In the present study, the depositional environment and geochemical characteristics of muddy hydrocarbon source rocks of P_1-2q were systematically evaluated using total organic carbon (TOC), Rock-Eval pyrolysis, vitrinite reflectance (Ro), reflected light microscopy, main and trace element, and biomarker parameters of 167 outcrop samples and 176 core samples. The TOC of P_1-2q is primarily concentrated within the range of 0.36% to 2.77%, with an average of 1.58%. This suggests that the overall evaluation of the hydrocarbon source rock is fair to good. The source rocks of P_1-2q predominately contain Type III and Type II₂ kerogen. The overall Tmax values of P_1-2q hydrocarbon source rocks are notably elevated, with the majority exceeding 490 °C or falling between 455 °C and 490 °C. The Ro value is between 0.90% and 2.00%, indicating that the maturity has reached a high, over-mature evolutionary stage. The trace element and biomarker parameters indicate that hydrocarbon source rocks of P_1-2q are predominantly slightly oxygen-rich, with a minor anoxic component. The asymmetric ‘V’ arrangement of the C₂₇-C₂₉ regular steranes indicates that the hydrocarbon parent material is predominantly derived from algae or aquatic organisms, with varying degrees of mixing with organic matter of terrestrial origin. The study of source rock geochemistry of the P_1-2q makes the exploration target of the southwest depression of the Tarim Basin more accurate in the complex tectonic geological environment. Full article

Free oil, rather than adsorbed oil, is the main contributor to shale oil production with current development technologies, and assessing oil contents in different occurrence states (adsorbed oil vs. free oil) is a critical component in evaluating the economics of shale wells and plays. Although various methodologies have been developed, there are still some fundamental issues in assessing the oil contents in different occurrence states in shale. In this study, a new method was developed to estimate the adsorbed and free oil contents in the Second Member of the Eocene Kongdian Formation (Ek₂) shales in Cangdong Sag, Bohai Bay Basin. This method combines the results of standard Rock-Eval pyrolysis and multi-step Rock-Eval pyrolysis with thin section petrography, X-ray diffraction for mineralogy, total organic carbon analyses, field emission scanning electron microscopy for pore morphology, and pore structure analyses by nitrogen physisorption and mercury intrusion porosimetry. Nine lithofacies were identified in a total of 50 shale samples, and the results show that the adsorbed and free oil are mainly contained in pores with diameters > 20 nm, and their contents are mainly controlled by organic matter abundance and thermal maturity of shales. While pore space volume influences the storage of shale oil, it is not a major determinant. Models of shale oil occurrence and its evolution are proposed, suggesting that the high S₁ contents of organic-rich and -fair shales, which the latter resulted from oil migration, are the most favorable exploration targets of Ek₂ shales. The findings of this study will help prioritize shale oil exploration targets in Ek₂ shales. Full article

The high exploration and development production capacity of the Jiyang Depression, Bohai Bay Basin, China in the early stage confirms the huge exploration and development potential of shale oil in the study area. Due to the complexity of the depositional mechanism in the study area, the distribution law of fine-grained sedimentary rocks is not well understood, which restricts further exploration breakthroughs. This paper comprehensively observes rock cores and thin sections, combines mineral components, Rock-Eval pyrolysis, rock-cutting logging and logging data to classify lithofacies, and clarifies the distribution law of various lithofacies. The research results show that, according to lithological characteristics, various lithofacies origins are classified into three categories: terrigenous, mixed, and endogenous sources, and six lithofacies types are distinguished: terrigenous low-organic-matter massive siltstone (LF1), terrigenous low-organic-matter massive mudstone (LF2), mixed-source medium-organic-matter massive mudstone (LF3), mixed-source medium-to-high-organic matter laminated-massive mudstone (LF4), mixed-source medium-to-high-organic-matter laminated mudstone (LF5), and endogenous-sourced medium-to-high-organic matter laminated limestone (LF6). The distribution of lithofacies in plane is symmetrical in the east–west direction and is characterized by a banded distribution; the distribution in profile shows a stable depositional process and a continuous depositional sequence. The various lithofacies depositional models have been summarized; the terrigenous input from the northern steep-slope zone has influenced the hydrodynamic conditions of the lake basin, significantly affecting the lithofacies depositional variations from the steep-slope zone to the deep-sag area. The geological evaluation of each lithofacies has been conducted; LF1 + LF4 + LF5 are classified as Class I—target reservoirs for shale oil development, while LF3 + LF6 are considered Class II—favorable reservoirs. The result of the study provide a reference for the classification of fine-grained sedimentary-rock facies and distribution characteristics, and the evaluation of shale-oil-reservoir sweet spots in graben lake basins. Full article

The present study focused on the Permian to Jurassic sequence in the Northern Highlands area, NW Jordan. The Permian to Jurassic sequence in this area is thick and deeply buried, consisting mainly of carbonate intercalated with clastic shale. This study integrated various datasets, including total organic carbon (TOC, wt%), Rock-Eval pyrolysis, visual kerogen examination, gross composition, lipid biomarkers, vitrinite reflectance (VRo%), and bottom-hole temperature measurements. The main aim was to investigate the source rock characteristics of these strata regarding organic richness, kerogen type, depositional setting, thermal maturity, and hydrocarbon generation timing. The Permian strata are poor to fair source rocks, primarily containing kerogen type (KT) III. They are immature in the AJ-1 well and over-mature in the NH-2 well. The Upper Triassic strata are poor source rocks in the NH-1 well and fair to marginally good source rocks in the NH-2 well, containing highly mature terrestrial KT III. These strata are immature to early mature in the AJ-1 well and at the peak oil window stage in the NH-2 well. The Jurassic strata are poor source rocks, dominated by KT III and KT II-III. They are immature to early mature in the AJ-1 well and have reached the oil window in the NH-2 well. Biomarker-related ratios indicate that the Upper Triassic oils and Jurassic samples are source rocks that received mainly terrestrial organic input accumulated in shallow marine environments under highly reducing conditions. These strata are composed mostly of clay-rich lithologies with evidence of deposition in hypersaline and/or stratified water columns. 1D basin models revealed that the Upper Triassic strata reached the peak oil window from the Early Cretaceous (~80 Ma) to the present day in the NH-1 well and from ~130 Ma (Early Cretaceous) to ~90 Ma (Late Cretaceous) in the NH-2 well, with the late stage of hydrocarbon generation continuing from ~90 Ma to the present time. The present-day transformation ratio equals 77% in the Upper Triassic source rocks, suggesting that these rocks have expelled substantial volumes of hydrocarbons in the NH-2 well. To achieve future successful hydrocarbon discoveries in NW Jordan, accurate seismic studies and further geochemical analyses are recommended to precisely define the migration pathways. Full article

The discovery of the Northern Copper Belt in SW Poland is a result of an extensive exploration project with a key role played by various science-related methods. The project relied on mapping the distribution of mineral zones in the entire Fore-Sudetic Monocline, a unit known for its occurrences of Cu-Ag orebodies. This approach involved the examination of historical drill cores from over 400 oil and gas holes in this area, with the collection of samples for laboratory analyses. A close relationship was confirmed between the distribution of orebodies and the transformation of organic matter. Rock-Eval pyrolysis was also performed on selected samples. The tests of rock specimens were accompanied by the reprocessing of historical gravimetric and seismic surveying results. Field magnetotelluric surveying was also performed in certain areas. This phase resulted in the identification of areas with a high probability of finding the best ore, allowing for the initiation of the drilling stage. So far, 37 exploratory boreholes have been drilled in those locations, nearly all of them with highly positive results. The Northern Copper Belt consists of three deposits, Nowa Sól, Mozów, and Sulmierzyce North, along with numerous prognostic areas distributed therebetween. The future production of copper, silver, and the accompanying valuable elements presents a chance to provide the whole of Europe with a new plentiful supply of those critical raw materials. Full article