Search Results (42)

The lacustrine to deltaic depositional systems of the Upper Jurassic Qigu Formation in the Yongjin area constitute a significant petroleum reservoir in the central Junggar Basin, China. Based on core observations, petrology analyses, paleoenvironment indicators and modern sedimentary analyses, sequence stratigraphy, lithofacies associations, sedimentary environment, evolution, and models were investigated. The Qigu Formation can be divided into a third-order sequence consisting of a lowstand systems tract (LST) and a transgressive systems tract (TST), which is further subdivided into six fourth-order sequences. Thirteen lithofacies and five lithofacies associations were identified, corresponding to shallow-water delta-front deposits. The paleoenvironment of the Qigu Formation is generally characterized by an arid freshwater environment, with a dysoxic to oxic environment. During the LST depositional period (SQ1–SQ3), the water depth was relatively shallow with abundant sediment supply, resulting in a widespread distribution of channel and mouth bar deposits. During the TST depositional period (SQ4–SQ6), the rapid rise in base level, combined with reduced sediment supply, resulted in swift delta retrogradation and widespread lacustrine sedimentation. Combined with modern sedimentary analysis, the shallow-water delta in the study area primarily comprises a composite system of single main channels and distributary channel-mouth bar complexes. The channel-bar complex eventually forms radially distributed bar assemblages with lateral incision and stacking. The distributary channel could incise a mouth bar deeply or shallowly, typically forming architectural patterns of going over or in the mouth bar. Reservoir test data suggest that the mouth bar sandstones are favorable targets for lithological reservoir exploration in shallow-water deltas. Full article

Lithology identification is one of the most important research areas in petroleum engineering, including reservoir characterization, formation evaluation, and reservoir modeling. Due to the complex structural environment, diverse lithofacies types, and differences in logging data and core data recording standards, there is significant overlap in the logging responses between different lithologies in the second member of the Lucaogou Formation in the Santanghu Basin. Machine learning methods have demonstrated powerful nonlinear capabilities that have a strong advantage in addressing complex nonlinear relationships between data. In this paper, based on felsic content, the lithologies in the study area are classified into four categories from high to low: tuff, dolomitic tuff, tuffaceous dolomite, and dolomite. We also study select logging attributes that are sensitive to lithology, such as natural gamma, acoustic travel time, neutron, and compensated density. Using machine learning methods, XGBoost, random forest, and support vector regression were selected to conduct lithology identification and favorable reservoir prediction in the study. The prediction results show that when trained with 80% of the predictors, the prediction performance of all three models has improved to varying degrees. Among them, Random Forest performed best in predicting felsic content, with an MAE of 0.11, an MSE of 0.020, an RMSE of 0.14, and a R² of 0.43. XGBoost ranked second, with an MAE of 0.12, an MSE of 0.022, an RMSE of 0.15, and an R² of 0.42. SVR performed the poorest. By comparing the actual core data with the predicted data, it was found that the results are relatively close to the XRD results, indicating that the prediction accuracy is high. Full article

Based on drilling, core and seismic data, combined with the regional tectonic sedimentary evolution background, the sedimentary environment of the Triassic carbonate rocks in the Mangeshlak Basin was studied. A sedimentary facies model of this set of carbonate rocks was established. Research has shown that the Mangeshlak Basin underwent a complete large-scale marine transgression–regression sedimentary evolution process during the Triassic. During the early to middle Triassic, seawater gradually invaded the northwest region of the basin from northwest to southeast and gradually regressed in the late Middle Triassic. In the lower part of the Triassic carbonate rocks, the primary components are developed granular limestone or dolomite with oolitic structures, interspersed with a small amount of thin mudstone, which is a good reservoir; the upper part of the Triassic is mainly composed of sedimentary mudstone and mudstone, which can form good sealings. The hill-shaped reflections of the platform edge facies, along with the high-frequency, strong-amplitude, and moderately continuous reflections within the restricted platform interior, are clearly visible on the seismic profile. These features are consistent with the sedimentary environment and lithofacies characteristics revealed by drilling data along the profile. Drilling and seismic data revealed that the sedimentary environment of the early and middle Triassic in the basin is mainly composed of shallow water platform edges and restricted platforms, as well as carbonate rock slopes and open non-marine shelves in deep water areas. A sedimentary facies model of the Triassic carbonate rock segment in the basin was established, comprising restricted platforms, platform edges, carbonate rock slopes, and non-marine shelves. Unlike the modified Wilson marginal carbonate rock platform model, the carbonate rock platform edge in the Mangeshlak Basin does not develop reef facies. Instead, it is mainly composed of oolitic beach (dam) sediments, making it the most favorable sedimentary facies zone for the Triassic reservoir development in the basin. Full article

The lithofacies and pore structural characteristics of shale reservoirs directly affect the exploration and development of shale gas. To clarify the exploration and development potential of the Lower Cambrian Shuijingtuo Formation (SJT) shale in the Middle Yangtze region, China, this study employs integrated experimental approaches, including optical and scanning electron microscopy (SEM) observations, X-ray diffraction (XRD) mineralogical analysis, and low-pressure gas (N₂/CO₂) adsorption, to classify mudstone lithofacies within the SJT and elucidate pore structural characteristics and dominant geological control across different lithofacies. The research results show that (1) Six main types of shale lithofacies are found in the STJ, including low-TOC massive calcareous mudstone (LMCM), low-TOC laminated mixed mudstone (LLMM), medium-TOC massive mixed mudstone (MMMM), high-TOC massive mixed mudstone (HMMM), high-TOC laminated siliceous mudstone (HLSM), and laminated argillaceous mudstone (LAM). (2) The pore types of SJT mudstone primarily include organic pores, intragranular clay mineral pores, and microfractures. The pore structure of mudstone is mainly controlled by clay mineral content and TOC content. However, the controlling factors of pore structure vary among different mudstone lithofacies. LMCM and LLMM are dominated by intragranular clay mineral pores, with their pore structures mainly controlled by clay mineral content. The pore types of HLMM and HLSM are organic pores, with pore structures predominantly controlled by TOC content. (3) The SJT mudstone gas reservoir exhibits diverse types, including HLSM, LAM, and LLMM. HLSM is characterized by the highest brittleness index and elevated pore volume (PV) and it can be considered the optimum lithofacies in the study area. Additionally, LLMM has the highest PV and relatively high brittleness index, positioning it as another significant reservoir target in the study area. Therefore, the Lower Cambrian shale gas reservoirs in the Middle Yangtze region exhibit diverse reservoir types. These research findings provide a scientific basis for the next phase of shale gas exploration planning in the Lower Cambrian. Full article

The exploration of shale oil in the Fengcheng Formation of the Permian system in the Hashan area shows considerable promise, with breakthroughs in a number of shale oil exploration wells. This study evaluates the source rocks in the Fengcheng Formation in the Hashan area to determine their types, clarify the quality and hydrocarbon potentials of the different types, and analyze the main factors affecting their quality and generation potential based on lithofacies classification. The results indicate that the Fengcheng Formation in the Hashan area contains four types of lithofacies: terrigenous clastic lithofacies, dolomitic mixed lithofacies, tephra-bearing mixed lithofacies, and alkaline mineral-bearing mixed lithofacies. The tephra-bearing mixed lithofacies source rocks have the best source rock quality, followed by terrigenous clastic lithofacies and dolomitic mixed lithofacies. The quality of the source rocks is mainly controlled by their sedimentary environment (including paleoenvironment, alkaline minerals, and volcanic activity), the hydrocarbon-generating properties of the source material, and maturity. Organic matter in the dolomitic mixed lithofacies and the alkaline mineral-bearing mixed lithofacies is more concentrated in deepwater-reducing environments with medium to high salinity and arid conditions. The main biological source material is green algae (Dunaliella), which is characterized by early hydrocarbon generation and the high transformation ratio of oil, allowing for rapid hydrocarbon generation at low maturity. However, as the maturity increases, the hydrocarbon-generating potential of the source rocks decreases rapidly. Organic matter in terrigenous clastic lithofacies is more concentrated in relatively shallow water in oxygen-depleted, low-salinity, arid to semi-arid environments, with cyanobacteria being the main biological source. Cyanobacteria have the characteristics of long hydrocarbon generation periods and high hydrocarbon potential, with the peak of hydrocarbon generation occurring later than green algae (Dunaliella). Therefore, even at a relatively high maturity level, the source rocks still maintain a relatively high hydrocarbon-generating potential. Moderate volcanic activity provides favorable conditions for organic matter accumulation. Full article

In tight reservoirs deposited in diverse sedimentary settings, the pore structure governs tight oil enrichment features and sweet-spot distribution. Taking the tight sandstone reservoirs of the lower third member of the Shahejie Formation in the Linnan Subsag of Bohai Bay Basin in China as an example, this study employs XRD to delineate petrological characteristics, while porosity and permeability measurements are used to quantify physical properties. In addition, thin section, SEM, HPMI, NMR, fractal theory, and cathodoluminescence experiments are applied to investigate pore structure characteristics and influencing factors. The results reveal two sedimentary systems: turbidity current and delta front deposits. Turbidite reservoirs exhibit the coarse pore-coarse throats (Type A), medium pore-medium throats (Type B), and fine pore-medium throats (Type C) pore structures. Delta front reservoirs are characterized by medium-pore-coarse-throat (Type D), medium-pore-fine-throat (Type E), and fine-pore-fine-throat (Type F) pore structures. Turbidite reservoirs show more favorable pore structures for oil exploration compared to delta fronts, in which lithofacies and diagenetic facies are the key influences. A genetic model identifies the highest-quality Type A forms in fine sandstone lithofacies under medium compaction–medium cementation–strong dissolution, with pore diameters averaging 10.84 μm in turbidite reservoirs. Conversely, the poorest Type F forms in argillaceous layered siltstone lithofacies under strong compaction, cementation, and weak dissolution diagenetic facies in delta fronts, with pore diameters averaging 0.88 μm. Consequently, the control effect of the pore quality means that Type A has the highest and Type F has the lowest oil-bearing capacity. These findings provide valuable guidance for the classification, evaluation, and exploration of tight oil sweet spots. Full article

In recent years, the successful application of gravity-flow deposit theory in major petroliferous basins in China had attracted extensive attention in the field of sedimentology and had become a key research frontier. This study utilized core, drilling, logging, and microphotograph data, along with low-temperature nitrogen adsorption and high-pressure mercury injection experiments. It discussed the characteristics of gravity-flow deposits, sedimentary microfacies, sedimentary models, and the significance of gravity-flow deposits to pore heterogeneity in shale reservoirs, focusing on the first submember of the Dongyuemiao Member (referred to as the Dong 1 Member) in the Fuling area of the Sichuan Basin. The results indicated the development of four types of mudrock in the Dong 1 Member: massive to planar laminated shell mudrock (F1), planar laminated bioclastic mudrock (F2), planar laminated silty mudrock (F3), and massive mudrock (F4). These corresponded to debris flow deposits (F1, F2), turbidite deposits (F3), and suspension deposits (F4). According to the characteristics of lithofacies combinations and sedimentary features, four sedimentary microfacies were identified: gravity-flow channel, tongue-shaped, lobate, and semi-deep lake mud. The Shell Banks were disturbed by earthquakes, tides, storms, and other activities. Silt, clay, fossil fragments, plant debris, and other materials were deposited under the influence of gravity, mixing with surrounding water to form an unbalanced and unstable fluid. When pore pressure exceeded viscous resistance, the mixed fluid became unbalanced, and gravity flow began to migrate from the slope to the center of the lake basin. A sedimentary unit of gravity-flow channel-tongue-shaped-lobate was developed in the Fuling area. The Fuling area’s gravity-flow depositional system resulted in distinct microfacies within the Dongyuemiao Member, each exhibiting characteristic lithofacies associations. Notably, lobate deposits preferentially developed lithofacies F3, which is distinguished by significantly higher clay mineral content (60.8–69.1 wt%) and elevated TOC levels (1.53–2.45 wt%). These reservoir properties demonstrate statistically significant positive correlations, with clay mineral content strongly influencing total pore volume and TOC content specifically enhancing mesopore development (2–50 nm pores). Consequently, the F3 lithofacies within lobe deposits emerges as the most prospective shale gas reservoir unit in the study area, combining optimal geochemical characteristics with favorable pore-structure attributes. Full article

The two-phase source rocks deposited during the Lower Cretaceous in the Persian Gulf Basin play a pivotal role in the regional hydrocarbon system. However, previous studies have lacked a macroscopic perspective constrained by the Tethyan Ocean context, which has limited a deeper understanding of their developmental patterns and hydrocarbon control mechanisms. To address this issue, this study aims to clarify the spatiotemporal evolution of the two-phase source rocks and their hydrocarbon control effects, with a particular emphasis on the critical impact of terrestrial input on the quality improvement of source rocks. Unlike previous studies that relied on a single research method, this study employed a comprehensive approach, including time series analysis, sequence stratigraphy, lithofacies, well logging, well correlation, seismic data, and geochemical analysis, to systematically compare and analyze the depositional periods, distribution, and characteristics of the two-phase source rocks under different sedimentary facies in the region. The goal was to reveal the intrinsic relationship between the Neo-Tethyan Ocean context and regional sedimentary responses. The results indicate the following: (1) the late Tithonian–Berriasian and Aptian–Albian source rocks in the Northern Persian Gulf were deposited during periods of extensive marine transgression, closely aligning with the global Weissert and OAE1d anoxic events, reflecting the profound impact of global environmental changes on regional sedimentary processes; (2) in the early stages of the Neo-Tethyan Ocean, controlled by residual topography, the Late Tithonian–Berriasian source rocks exhibited a shelf–intrashelf basin facies association, with the intrashelf basin showing higher TOC, lower HI, and higher Ro values compared to the deep shelf facies, indicating more favorable conditions for organic matter enrichment; (3) with the opening and deepening of the Neo-Tethyan Ocean, the Aptian–Albian source rocks at the end of the Lower Cretaceous transitioned to a shelf–basin facies association, with the basin facies showing superior organic matter characteristics compared to the shelf facies; (4) the organic matter content, type, and thermal maturity of the two-phase source rocks are primarily controlled by sedimentary facies and terrestrial input, with the Aptian–Albian source rocks in areas with terrestrial input showing significantly better quality than those without, confirming the decisive role of terrestrial input in improving source rock quality. In summary, this study not only reveals the differences in the depositional environments and hydrocarbon control mechanisms of the two-phase source rocks, but also highlights the core role of terrestrial input in enhancing source rock quality. The findings provide a basis for facies selection in deep natural gas exploration in the Zagros Belt and shale oil exploration in the western Rub’ al-Khali Basin, offering systematic theoretical guidance and practical insights for hydrocarbon exploration in the Persian Gulf and broader tectonic domains. Full article

The transitional shale system of the Longtan Formation (LTF) is widely distributed in the Sichuan Basin. However, the lithofacies of the LTF shale system exhibit vertical variations, with frequent interbedding of blocks, and shale–sand–coal sequences, which makes identifying “sweet spots” a challenging task. To address this issue, lithofacies associations were investigated based on well log analysis from 30 wells, and experimental data from 19 well samples, including X-ray diffraction, total organic carbon (TOC), pore structure characterization, and methane isothermal adsorption tests. Four lithofacies associations were classified: carbon–shale interbedding (I-1), shale(carbon)–coal interbedding (I-2), shale–sand interbedding (II), and shale–sand–coal assemblage (III). A favorable lithofacies association index (Com) was developed, providing a quantitative method for identifying favorable lithofacies. The results indicate that among the four lithofacies associations, I-2 is the most favorable lithofacies association. The Com index threshold for favorable lithofacies is defined as 0.6, and for the most favorable lithofacies, it is 0.7. Overall, favorable lithofacies are primarily distributed in the Suining-Dazu and Lujiao areas. Full article

Haian Depression is one of the key areas for oil and gas resource replacement in Jiangsu Oilfield. Since the 13th cycle of the Five Year Plan, with the continuous improvement in the exploration level of the Taizhou Formation (K₂t), the difficulty of tapping potential has gradually increased. It is urgent to change our thinking and expand new exploration layers. From the perspective of oil and gas display frequency in different layers of the Haian Depression, except for K₂t, the oil and gas systems with the Fusan Member (E₁f₃) as the main reservoir have good oil and gas display frequency, demonstrating great exploration potential. This study of sedimentary characteristics is the basis of analyzing the sedimentary environment and lithofacies paleogeographic conditions and is of great significance for determining the distribution range of subtle oil and gas reservoirs. Based on this understanding, this study was specially established to systematically analyze the logging curves of forty-three wells in the research area, combined with core observations of eighteen coring wells and the analysis of eight seismic profiles. The results show that the low slope, warm and humid climate, sufficient provenance, and frequent lake level rise and fall cycles during the deposition period of the E₁f₃ member of the Haian Sag provide a favorable depositional background for the development of shallow water delta in the study area. There are many gullies in the research area, mainly consisting of U-shaped gullies and W-shaped gullies. Slope breaks are mainly affected by structural factors leading to fractures, and the types are mostly fault terrbreakslope breaks. In the study area, the shallow water delta deposits during the deposition period of the four key sand groups in the Fu3 Formation are dominated by the shallow water delta front and shallow water prodelta. The shallow water delta plain subfacies are not significantly developed because of erosion. The sand bodies are mainly distributed in the Sunjiawa Subdepression, and the Fuan Subdepression in the north of the depression, and the sand bodies in the plane show the filling characteristics of the strip. Based on the above research, a sedimentary model of shallow water delta during the E₁f₃ section of the Haian Depression was established, providing a geological basis for the design of exploration and development plans for hidden oil and gas reservoirs in the next step. Full article

Cambrian subsalt dolomite is an important strategic area for natural gas exploration in the Tarim Basin. The gypsum-salt rocks, argillaceous mudstone and argillaceous dolomite strata developed in large areas of the Middle Cambrian can be used as good caprocks. The sealing ability and favorable area distribution of the Middle Cambrian caprock in the Tarim Basin are studied through the lithofacies paleogeography and microscopic evaluation of the Middle Cambrian strata in this paper. Based on the 2D seismic interpretation covering the entire basin, combined with data from drilling, outcrops, well logging, core samples and thin sections, the sedimentary characteristics and lithofacies paleogeography of the Middle Cambrian were studied and then the thickness of the Middle Cambrian gypsum-salt rocks, gypsiferous mudstone and gypsiferous dolomite was analyzed in the Tarim Basin. Studies suggest that the Middle Cambrian is primarily characterized by the development of restricted-platform facies. In the Awati Depression, the northern part of the Tazhong Uplift, the southern part of the Manxi Low Uplift, and the central and northern parts of the Bachu Uplift, the thickness of the gypsum-salt rock strata is relatively large. Moreover, centered on the northern part of the Bachu Uplift, the thickness of the gypsum-salt rocks decreases irregularly towards the periphery, forming a circumferential distribution. To investigate the sealing ability of caprocks, 64 core samples from four wells were examined under a microscope, and physical parameters as well as breakthrough-pressure tests were conducted. By establishing correlations between various parameters, the sealing ability of different rock types in the Cambrian formation within the study area was quantitatively assessed. The research suggests that gypsum-salt rocks exhibit superior sealing ability compared to gypsiferous mudstone and gypsiferous dolomite, but factors such as faults and geological conditions of gypsum can influence the sealing performance of caprocks. According to both micro- and macro-scale evaluations of the Cambrian strata in the study area, along with constraints imposed by actual drilling exploration results, a comprehensive evaluation method for assessing caprock sealing ability has been established. The results suggest that the Awat Depression, the western and southern parts of the Manxi Low Uplift, the northern and western parts of the Tazhong Uplift, and the central part of the Tabei Uplift are favorable areas for the development of caprocks. Full article

During the Rhuddanian–Aeronian interglacial period, global geological events such as glacial melting, synsedimentary volcanic activity, biological resurgence, and large-scale marine transgressions caused frequent fluctuations in paleoproductivity, climate changes, and sea level variations. These paleoenvironmental transitions directly influenced the development characteristics of shale lithofacies. This study investigates the Longmaxi Formation shale in the Changning area in the Southern Sichuan basin, focusing on 28 core samples from Well N1. Using scanning electron microscopy, QEMSCAN, TOC, XRD, and major and trace element analyses, we reconstructed the paleoenvironmental transitions of this period and explored their control over shale lithofacies types and mineral compositions. Four shale lithofacies were identified: carbonate rich lithofacies (CRF), biogenic quartz-rich lithofacies (BQRF), detrital clay-rich lithofacies (CRDF), and detrital quartz-rich lithofacies (DQRF). During the Rhuddanian period, rising global temperatures caused glacial melting and rapid marine transgressions. The low oxygen levels in bottom waters, combined with upwelling and abundant volcanic material, led to high paleoproductivity. This period primarily developed BQRF and CRF. Rich nutrients and abundant siliceous organisms, along with anoxic to anaerobic conditions, provided the material basis and preservation conditions for high biogenic quartz and organic matter content. High paleoproductivity and anoxic conditions also facilitated the precipitation of synsedimentary calcite and supplied Mg²⁺ and SO₄²⁻ for the formation of iron-poor dolomite via sulfate reduction. From the Late Rhuddanian to the Mid-Aeronian, the Guangxi orogeny caused sea levels to fall, increasing water oxidation and reducing upwelling and volcanic activity, which lowered paleoproductivity. Rapid sedimentation rates, stepwise global temperature increases, and the intermittent intensification of weathering affected terrigenous clastic input, resulting in the alternating deposition of CRF, CRDF, and DQRF. Two favorable shale gas reservoirs were identified from the Rhuddanian–Aeronian period: Type I (BQRF) in the L1–L3 Layers, characterized by high TOC and brittleness, and Type II (DQRF) in the L4 Layer, with significant detrital quartz content. The Type I-favorable reservoir supports ongoing gas production, and the Type II-favorable reservoir offers potential as a future exploration target. 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 Upper Miocene–Pliocene Kampungbaru Formation crops out in the easternmost part of the Lower Kutai Basin, Indonesia. The sedimentological analysis of seven outcrops was carried out, and a total of twenty-five samples from these outcrops was analyzed for bulk geochemistry, organic petrography, and bulk and clay mineralogy to assess the effect of the climate and depositional environment on organic matter enrichment. The Kampungbaru Formation consists of interbedded sandstone, siltstone, claystone, and thick coal beds, which were classified into eleven lithofacies. Subsequently, seven facies associations were identified, namely the fluvial-dominated distributary channel, sheet-like sandstone, tide-influenced distributary channel, mouth bar, crevasse splay, delta plain, and delta front. The coal facies generally have a high amount of total organic carbon (TOC, 5.1–16.9; avg. 10.11 wt.%), and non-coal layers range from 0.03 to 4.22 wt.% (avg. 1.54 wt.%). The dominant maceral is vitrinite, while liptinite occurs only rarely in the samples. Organic matter is inferred to have originated from terrestrial plants growing in mangrove swamps. Identified clay minerals include varying proportions of kaolinite, illite, chlorite, and mixed layer illite/smectite (I/S). Kaolinite, which commonly constitutes up to 30% of the clay volume, indicates intensive chemical weathering during a warm and humid climate. In accordance with the Köppen climate classification, the paleoclimate during the deposition of the Kampungbaru Formation is classified as type Af, which is a tropical rainforest. Tropical climate was favorable for the growth of higher plants and deposition of organic matter under anoxic conditions and led to higher amounts of TOC in the Kampungbaru Formation. Full article