Search Results (233)

This study presents an integrated approach using organic geochemistry and incident-light organic petrographic microscopy techniques to characterize the kerogen type, hydrocarbon potential, thermal maturity, and effective depositional environment of the Eocene Liushagang Formation intervals in the western Huangtong Sag, eastern Bailian Sag, central Huachang Sub-uplift, and Southern Slope Zone area in the Fushan Depression, Beibuwan Basin. The results show that the hydrocarbon potential of these organic-rich lacustrine shale areas is mainly dependent on the depositional environment and the present-day burial depth of sediments. Oscillations and transitions between (i) rocks with dominant allochthonous organic matter (including primary/reworked vitrinite and inertinite macerals and terrestrial debris particles) representing a large influence of continental sediments (e.g., source supply direction) and (ii) rocks with dominant autochthonous organic matter (e.g., alginite) indicate a distal and stable lacustrine basin depositional environment. The source rock thickness ranges from 40.1 to 387.4 m. The average TOC of the Liushagang Formation in the Fushan Sag is between 0.98% and 2.00%, with the highest organic matter abundance being in the first and second sections of the Liushagang Formation, presenting as high-quality source rocks. The organic matter is predominantly Type II₁ and Type II₂. The highest vitrinite reflectance (1.14%) is in the Huangtong and Bailian Sags. The source rocks of the second section of the Liushagang Formation are primary hydrocarbon generators, contributing 55.11% of the total generation. Hydrocarbon sequestration peaks at %Ro 0.80%, with a maximum efficiency of 97.7%. The cumulative hydrocarbon generation of the Liushagang Formation is 134.10 × 10⁸ tons, with 50.52 × 10⁸ tons having been expelled and 83.58 × 10⁸ tons remaining. E₂L_2X and E₂L_2S have maximum hydrocarbon displacement intensities of 184.22 × 10⁴ t/km² and 45.39 × 10⁴ t/km², respectively, with cumulative displacements of 52.99 × 10⁸ tons and 15.58 × 10⁸ tons. The oil and gas accumulation system is highly prospective, showing significant exploration potential. Full article

The Zonguldak coal basin is the area with the most important hard coal reserves in Turkey. This study focuses on coal samples extracted from three seams of the Kozlu Formation, specifically from the Kozlu underground mine, to assess the coals’ organic geochemical and petrographic properties. Analytical methods, including TOC-pyrolysis, biomarker analysis, and maceral distribution studies, were employed. Based on these analyses, the paleoenvironmental conditions and hydrocarbon generation potential of the coals were evaluated. The results reveal that the coals, characterized by high TOC, high HI, and low OI, contain type II–III kerogen. These findings, coupled with the high QI and low BI values, suggest the presence of oil–gas prone source rocks. Elevated Tmax (457–466 °C) and Rr (0.89%–1.17%) values indicate a maturity level ranging from mature to overmature stages. High GI and GWI values suggest a significant degree of gelification and wet conditions during formation. The high Pr/Ph (1–6.58), C₃₁R/C₃₀ hopane (<0.25), and low DBT/P (0.27–0.50) ratios show that the Acılık seam was formed in a lacustrine environment under anoxic–suboxic conditions, whereas the Büyük and Domuzcu seams were formed in a fluvial/deltaic environment under oxic conditions. The findings of this study suggest that the paleovegetation in coal-forming environments consisted of aquatic and herbaceous plants. 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

Regional mudstone cap rock has an important influence on the oil and gas distribution of the oil source faults below it. Therefore, studying the influence of these mudstone cap rocks on the hydrocarbon distribution pattern is fundamental to understanding the oil and gas distribution of the lower generation and upper reservoir reservoirs in the Bohai Bay Basin. This study classified two types of hydrocarbon diversion from oil source faults: blockage diversion and seepage diversion. To locate them, we established a method to predict the areas with blockage diversion and seepage diversion separately by superimposing the sealing and leakage parts of the regional mudstone cap rock with the regions of the connected distribution of sand bodies and the favorable hydrocarbon transport sites of the oil source faults, respectively. We used this approach to predict the locations where hydrocarbons are diverted by the oil source faults under the regional mudstone cap rocks in the first and second sections of the Dongying Formation (E₃d_1-2) in the Liuchu area of the Raoyang Sag, Bohai Bay Basin. The results show that the regional mudstone cap rock’s blockage diversion occurs mainly in the south-central area of Liuchu, with a localized distribution in the northern part. The seepage diversion site is primarily located in the northeastern area and is also found locally in the west. Both diversions are beneficial for the accumulation of hydrocarbons from the source rocks of the first member of the Shahejie Formation (E₃s₁) to the upper second member of the Dongying Formation (E₃d_2U). The latter can also accumulate hydrocarbons in the Guantao Formation (N₁g). The results align with the hydrocarbon distribution, demonstrating the feasibility of our method to predict various oil source fault diversion sites under the regional mudstone cap rock. This prediction method offers valuable guidance for exploring the lower generation and upper reservoir hydrocarbon accumulations in hydrocarbon-bearing basins. Full article

Low-maturity shale oil predominates in shale oil resources. China’s onshore shale oil, particularly the Cretaceous Nenjiang Formation in the Songliao Basin, holds significant potential for low-maturity shale oil, presenting promising exploration and development prospects. This study delves into the hydrocarbon generation conditions, reservoir characteristics, and oil-bearing property analysis of the mud shale from the Nen-1 and Nen-2 sub-formations of the Nenjiang Formation to pinpoint favorable intervals for shale oil exploration. Through the integration of lithology, pressure, and fracture distribution data in the study area, favorable zones were delineated. The Nen-1 sub-formation is widely distributed in the Changling Depression, with mud shale thickness ranging from 30 to 100 m and a total organic content exceeding 2.0%. Type I kerogen predominated as the source rock, while some samples contained type II kerogen. Organic microcomponents primarily comprised algal bodies, with vitrinite reflectance (R_o) ranging from 0.5% to 0.8%. Compared to Nen-1 shale, Nen-2 shale exhibited less total organic content, kerogen type, and thermal evolution degree, albeit both are conducive to low-maturity shale oil generation. The Nen-1 and Nen-2 sub-formations predominantly consist of clay, quartz, feldspar, calcite, and pyrite minerals, with minor dolomite, siderite, and anhydrite. Hydrocarbons primarily reside in microfractures and micropores, including interlayer micropores, organic matter micropores, intra-cuticle micropores, and intercrystalline microporosity, with interlayer and intra-cuticle micropores being dominant. The free oil content (S₁) in Nen-1 shale ranged from 0.01 mg/g to 5.04 mg/g (average: 1.13 mg/g), while in Nen-2 shale, it ranged from 0.01 mg/g to 3.28 mg/g (average: 0.75 mg/g). The Nen-1 and Nen-2 sub-formations are identified as potential intervals for shale oil exploration. Considering total organic content, oil saturation, vitrinite reflectance, and shale formation thickness in the study area, the favorable zone for low-maturity shale oil generation is primarily situated in the Heidimiao Sub-Depression and its vicinity. The Nen-2 shale-oil-enriched zone is concentrated in the northwest part of the Heidimiao Sub-Depression, while the Nen-1 shale-oil-enriched zone lies in the northeast part. Full article

The marine carbonates in the Ordovician Majiagou Formation in the Ordos Basin have significant exploration potential. Research has focused on their thermal history and hydrocarbon accumulation stages, as these are essential for guiding the exploration and development of hydrocarbons. In this paper, we study the thermal evolution history of the carbonate reservoirs of the Ordovician Majiagou Formation in the east-central Ordos Basin. Furthermore, petrographic and homogenization temperature studies of fluid inclusions were carried out to further reveal the hydrocarbon accumulation stages. The results demonstrate that the degree of thermal evolution of the Ordovician carbonate reservoirs is predominantly influenced by the deep thermal structure, exhibiting a trend of high to low values from south to north in the central region of the basin. The Fuxian area is located in the center of the Early Cretaceous thermal anomalies, with the maturity degree of the organic matter ranging from 1 to 3.2%, with a maximum value of 3.2%. The present geothermal gradient of the Ordovician Formation exhibits the characteristics of east–high and west–low, with an average of 28.6 °C/km. The average paleo-geotemperature gradient is 54.2 °C/km, the paleoheat flux is 55 mW/m², and the maximum paleo-geotemperature reaches up to 270 °C. The thermal history recovery indicates that the Ordovician in the central part of the basin underwent three thermal evolution stages: (i) a slow warming stage before the Late Permian; (ii) a rapid warming stage from the end of the Late Permian to the end of the Early Cretaceous; (iii) a cooling stage after the Early Cretaceous, with the hydrocarbon production of hydrocarbon source rocks weakening. In the central part of the basin, the carbonate rock strata of the Majiagou Formation mainly developed asphalt inclusions, natural gas inclusions, and aqueous inclusions. The fluid inclusions can be classified into two stages. The early-stage fluid inclusions are mainly present in dissolution holes. The homogenization temperature is 110–130 °C; this coincides with the hydrocarbon charging period of 210–165 Ma, which corresponds to the end of the Triassic to the end of the Middle Jurassic. The late-stage fluid inclusions are in the dolomite vein or late calcite that filled the gypsum-model pores. The homogenization temperature is 160–170 °C; this coincides with the hydrocarbon charging period of 123–97 Ma, which corresponds to the late Early Cretaceous. Both hydrocarbon charging periods are in the rapid stratigraphic warming stage. Full article

The Myanmar region experienced the subduction of the Indian Ocean plate to the West Burma block and suffered from the land–land collision between the Indian continent and the West Burma block that occurred from the Late Cretaceous to the Cenozoic. Its tectonic evolution has been complex; thus, oil and gas exploration is difficult, and the overall degree of research has been low. Recent exploration has been hindered by a lack of knowledge on the evolution of the petroleum system. To address this, we conducted hydrocarbon generation and accumulation modeling using both the 2D MOVE and Petro-Mod software 2017 for a complex tectonic section in the Northern Central Myanmar Basin. The results show that the maturity threshold depth of the Cretaceous source rocks in the study area is shallow, and the underground depth of 1200 m to 1400 m has reached the hydrocarbon generation threshold, indicating the start of hydrocarbon generation. Since 48 Ma, the Ro of the source rocks has reached 0.7%, became mature quite early. The Late Cretaceous Paleocene and Eocene formation, located in the southeastern part of the study area, migrated and accumulated hydrocarbons towards the western arc zone in the Eocene and Miocene, respectively. It is worth noting that although the oil and gas potential of each layer in the island arc uplift zone is relatively low, which is conducive to the migration and accumulation of oil and gas generated by the source rocks of the depression towards the island arc zone, shallow areas with developed extensional faults should be avoided. This study is the first to conduct a preliminary assessment and prediction of oil and gas resources, which will provide exploration guidance and reference for the study area and its surrounding areas in the future. 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 inexplicable distribution of souring wells (presence of H₂S gas) of the unconventional Montney Formation hydrocarbon resource (British Columbia; BC) is investigated by analysing sulphur and oxygen isotopes, coupled with XRD mineralogy, scanning electron microscopy (SEM), and energy dispersive spectroscopy (EDX). The sulphur isotopic analysis indicates that the sulphur isotopic range for Triassic anhydrite (δ34S 8.9 to 20.98‰ VCDT) is the same as the H₂S sulphur that is produced from the Montney Formation (δ34S 9.3 to 20.9‰ VCDT). The anhydrite in the Triassic rocks is the likely source of the sulphur in the H₂S produced in the Montney Formation. The deeper Devonian sources are enriched in ³⁴S and are not the likely source for sulphur (δ34S 17.1 and 34‰ VCDT). This is contradictory to studies on Montney Formation producers in Alberta, with heavier (³⁴S-enriched) sulphur isotopic signatures in H₂S gas of all souring Montney Formation producers. These studies conclude that deep-seated faults and fractures have provided conduits for sulphate and/or H₂S gas to migrate from deeper sulphur sources in the Devonian strata. There are several wells that show a slightly heavier (³⁴S-enriched) isotopic signature (δ34S 18 to 20‰ VCDT) within the Montney Formation H₂S gas producing within close proximity to the deformation front. This variation may be due to such deep-seated faults that acted as a conduit for Devonian sulphur to migrate into the Montney Formation. Our geological model suggests the sulphate-rich fluids have migrated from the Charlie Lake Formation prior to hydrocarbon generation in the Montney Formation (BC). Sulphate has concentrated in discrete zones due to precipitation in conduits like fracture and fault systems. The model fits the observation of multi-well pads containing both sour- and sweet-producing wells indicating that the souring is occurring in very narrow and discrete zones with the Montney Formation (BC). Government agencies and operators in British Columbia should map the anhydrite-rich portions of the Charlie Lake Formation, together with the structural elements from three-dimensional seismic to reduce the risk of encountering unexpected souring. Full article

This study investigates the genesis of analcite in black shale from continental lakes and its implications for hydrocarbon enrichment, with a case study of the Permian Pingdiquan Formation in the Junggar Basin, Xinjiang, China. As an alkaline mineral, analcite is extensively developed in China’s lacustrine black shale hydrocarbon source rocks and is linked to hydrocarbon distribution. However, the mechanisms of its formation and its impact on hydrocarbon generation and accumulation remain insufficiently understood. This paper employs a multi-analytical approach, including petrological observations, geochemical analysis, and X-ray diffraction, to characterize analcite and its association with hydrocarbon source rocks. The study identifies a hydrothermal sedimentary origin for analcite, suggesting that it forms under conditions of alkaline lake water and volcanic activity, which are conducive to organic matter enrichment. The analcite content in the studied samples exhibits a significant variation, with higher contents associated with hydrocarbon accumulation zones, suggesting its role in hydrocarbon generation and accumulation. This paper reports that analcite-bearing rocks display characteristics of high-quality reservoirs, enhancing the permeability and porosity of the rock, which is essential for hydrocarbon storage and migration. In conclusion, this paper underscores the importance of analcite as a key mineral indicator for hydrocarbon potential in black shale formations and provides valuable insights for further geological and hydrocarbon exploration in similar settings. Full article

The Chang 7, Chang 8, and Chang 9 members of the Triassic Yanchang Formation in the Fuxian–Ganquan area of the Ordos Basin all develop lacustrine shales. However, current geological research and shale oil and gas exploration mainly focus on Chang 7 shale, with little attention given to Chang 8 and Chang 9 shale formations. Based on the experimental data from whole-rock mineral analysis, organic geochemical analysis, field-emission scanning electron microscopy analysis, and hydrocarbon generation simulation experiments, combined with well-logging data, the shale distribution, mineral composition, source rock characteristics, reservoir properties, and oil and gas contents of Chang 7, Chang 8, and Chang 9 shales were comprehensively analyzed. Moreover, the effect of integrated exploration of multilayer shales was evaluated based on a specific example. The results indicate that three sets of shales are extensively developed in the Yanchang Formation in the study area, but their thicknesses and distribution ranges vary greatly, and Chang 7 shale has the largest thickness and distribution range. Their clay mineral contents are relatively high, reaching an average of 46.7%. Also, the types of their organic matter are mainly Type I-II₁, with high abundance and an average organic carbon content of 4.7%. Their vitrinite reflectance is between 0.7% and 1.3%, indicating that they are in the oil–gas symbiosis stage. Furthermore, they develop various types of nanoscale pores, such as intergranular pores, intragranular pores, and organic pores, and their porosity has an average value of 2.51% and increases significantly after crude oil is extracted. Oil and gas coexist in these three sets of shales, with an average free hydrocarbon content of 3.9 mg/g and an average gas content of 2.6 m³/t. Finally, in order to explore the integrated exploration and development of multilayer shale oil and gas formations, multilayer staged fracturing tests were carried out on six vertical wells for three sets of shales; the production results show that the gas production rate significantly increased by threefold, with a daily oil production rate of more than 1 ton. Full article

In order to study the distribution pattern of oil and gas near the lower-source, upper-storage type of oil source faults in the hydrocarbon-bearing basins, a set of prediction methods favourable to oil and gas migration and accumulation were established by superimposing the parts of the oil source fault-associated traps, the contiguously distributed sand bodies and the lateral sealing position of faults. The trap associated with a fault can be determined by the fault’s convex part on the fault plane’s morphology map, the fault throw displacement curve and the intersection of faults on the structure map. The set of sand bodies can be determined by the sand-to-shale ration of the formation. The lateral sealing position of faults can be investigated by the shale content of the fault. This study is based on our case study of the Dazhangtuo Fault in the lower sub-member of the 1st member (Es₁^L) of the Shahejie formation in the northern Qikou Sag of Bohai Bay Basin. The results illustrate 4 fault nose traps formed by fault line deflection in the Es₁^L formation of the Dazhangtuo Fault, 2 each in the middle and eastern end. The Dazhangtuo Fault is favorable for oil and gas migration except at the eastern and western ends and the middle part of the fault. The fault-associated traps in the Es₁^L formation that are highly favorable for hydrocarbon migration and accumulation (overlapping site of associated traps and favorable location for oil and gas migration) are distributed in the eastern and central parts of the Dazhangtuo Fault. In contrast, those moderately favorable for hydrocarbon migration and accumulation (associated trap at a certain distance from the favorable location for oil and gas migration in the Dazhangtuo Fracture) are locally distributed in the east. Both traps are conducive to accumulating hydrocarbons from the underlying source rock in the Es₃ formation. Such observations are consistent with the current confirmed hydrocarbon distribution, thus validating the feasibility and accuracy of predicting the distribution of traps related to oil source faults favorable for hydrocarbon migration and accumulation, it can be used to guide the exploration of the lower-source, upper-storage type of hydrocarbon accumulations in the hydrocarbon-bearing basins. Full article

The Parecis Basin, one of Brazil’s most extensive intracratonic basins, holds significant potential for hydrocarbon exploration. Despite its vast size, Parecis has yet to be extensively explored, with only five wildcat wells drilled. So far, no commercial discoveries have been announced. Regional studies have suggested Paleozoic sedimentation, while recent analyses have revealed a Neoproterozoic infill. Its tectonic model is still a matter of debate, and to date, no detailed structural map for the whole basin has been published. The present work proposes a new detailed structural map of the Parecis Basin based on a four-step interpretation workflow integrating seismic and gravimetric data. The first step includes converting the public 2D seismic lines to the depth domain. The second step is estimating the residual Bouguer anomaly, where the computed residual anomalies should relate to the basin’s tectonic features. The third step comprises the 2D forward modeling of the gravimetric anomalies using the 2D seismic interpretation as a constraint. The final step compiled all the interpreted features into our new structural map. This map reveals the top of the basement, forming a complex framework of horsts and grabens. Normal faults define the main structural style in the basin. Further, we could recognize thick, high-density bodies embedded in the crystalline basement. These bodies consist of Orosian–Calimian (1.8–1.6 Ga) mafic and ultramafic rocks, which may be a potential source for hydrogen exploration in the basin. Subsequent geophysical and geochemical surveys will assess the hydrogen potential in the area. Full article

Light oil, a high-quality energy resource abundant in deep basins, is prevalent in the northern zone of the Dongying Depression. To elucidate the formation mechanism of light oil reservoirs, this study investigates the molecular and stable isotope composition, biomarkers, light hydrocarbons, and diamondoid compositions of petroleum. The results reveal that the gas primarily consists of oil-cracking gas from a late filling event, mixed with oil-associated gas generated during the source rock’s “oil window” maturity phase. Methane exhibits enriched light carbon isotopes, indicating noticeable migration fractionation effects. The crude oil in the same deep strata exhibits high maturity, originating from both terrestrial and aquatic organic matter in the source materials. Molar proportions of n-alkanes and light hydrocarbon indices (Tol/nC₇, nC₇/MCH) indicate significant evaporative fractionation in the petroleum reservoirs. This fractionation process modified early-formed oil reservoirs due to the late filling of highly mature gas reservoirs. The evaporative fractionation at different stages has varying effects on the diamondoid ratio (1- + 2-MA)/(3- + 4-MD). It is considered a pivotal mechanism in the formation of deep condensate reservoirs and volatile oil reservoirs. Full article

New discoveries and breakthroughs have been made in recent years in the deep parts of the central Junggar Basin, where the Jurassic reservoirs are unconventionally dense with abnormal overpressure development. The development and distribution of overpressure in this basin and the influence of overpressure on petroleum accumulation were analyzed. There are two extremely high overpressure systems in the Jurassic Badaowan and Xishangyao formations, from where the abnormal overpressure in the strata overburdened Jurassic reservoirs was transferred. Paleopressure simulations show that hydrocarbon generation pressurization of the main source rocks in the Badaowan Formation is a process characterized by at least two phases of overpressure increase followed by a phase of overpressure release. Overpressure inhibits the thermal evolution of source rocks in the study area, resulting in lower values of maturity parameter Ro at depths > 4500 m compared with the normal values at depths < 4500 m. The deep reservoirs > 4500 m are very dense, with strong compaction and little retention of primary pore space, indicating the overpressure did not protect the primary pores, while the over-pressured acidic fluid promoted the formation of dissolved pore space. Overpressure and faults are two key factors of petroleum migration, and they jointly control petroleum accumulation in the central Junggar Basin. Full article