Over-mature Stage Research Articles

An enhanced presence of tricyclic terpanes in the Triassic oils from the tight conglomerate reservoir in the Mahu Sag, Junggar Basin, NW China

A major exploration breakthrough has been made in the Mahu Sag, Junggar Basin. However, the origin of oils from Triassic Baikouquan Formation (T1 b) remains debated. In this study, 20 oils and 44 cores were selected to investigate their distributions of tricyclic terpanes (TTs). The results show that the relative abundance of TTs in oils is higher than those of hopanes due to a high maturity. Permian Wuerhe Formation (P2 w) cores are dominated by C20TT. Permian Fengcheng Formation (P1 f) samples, predominated by C23TT, are mature to high-mature, while Permian Jiamuhe Formation (P1 j) samples, having the same abundance of C21TT and C23TT, are in the over-mature stage. Maturity may be a likely possible reason for the different occurrences of C19–C23TTs between P1 f and P1 j as their organic matter source and depositional environment were similar. High gammacerane and C29 sterane occurred in T1 b oils, P1 f and P1 j cores, while those in P2 w are little, indicating P2 w had a minor contribution for T1 b oils. The δ13C values of oils and P1 f are similar and lower than those of P2 w and P1 j source rocks. Therefore, it is preliminarily speculated that the oils may be sourced from the deep buried P1 f in the over-mature stage.

Pore formation and evolution mechanisms during hydrocarbon generation in organic-rich marl

Marine organic-rich marl is not only a high-quality hydrocarbon source of conventional oil and gas, but also a new type and field of unconventional oil and gas exploration. An understanding of its pore structure evolution characteristics during a hydrocarbon generation process is theoretically significant and has application prospects for the exploration and development of this special type of natural gas reservoirs. This study conducted thermal simulation of hydrocarbon generation under near-geological conditions during a whole process for cylinder samples of low mature marine organic-rich marl in the Middle Devonian of Luquan, Yunnan Province, China. During this process, hydrocarbon products at different evolution stages were quantified and corresponding geochemical properties were analyzed. Simultaneously, field emission scanning electron microscopy (FE-SEM) and low-pressure gas adsorption (CO2, N2) tests were applied to the corresponding cylinder residue samples to reveal the mechanisms of different types of pore formation and evolution, and clarify the dynamic evolution processes of their pore systems. The results show that with an increase in temperature and pressure, the total oil yield peaks at an equivalent vitrinite reflectance (VRo) of 1.03% and is at the maximum retention stage of liquid hydrocarbons, which are 367.51 mg/g TOC and 211.67 mg/g TOC, respectively. The hydrocarbon gas yield increases continuously with an increase in maturity. The high retained oil rate at the peak of oil generation provides an abundant material basis for gas formation at high maturity and over-maturity stage. The lower limit of VRo for organic matter (OM) pore mass development is about 1.6%, and bitumen pores, organic-clay complex pores together with intergranular pores, grain edge seams and dissolution pores constitute a complicated pore-seam-network system, which is the main reservoir space for unconventional carbonate gas. Pore formation and evolution are controlled synergistically by hydrocarbon generation, diagenesis and organic-inorganic interactions, and the pattern of pore structure evolution can be divided into four stages. A pore volume (PV) and a specific surface area (SSA) are at their highest values within the maturity range of 1.9% to 2.5%, which is conducive to exploring unconventional natural gas.

Mechanical properties of shale during pyrolysis: Atomic force microscopy and nano-indentation study

Quantitative characterization of the geo-mechanical properties of shale and organic matter (OM) holds paramount significance in the assessment of shale gas reserves and the design of hydraulic fracturing. However, the mechanical evolution processes during shale hydrocarbon generation and its influencing factors have received limited attention. This study examines the changes in shale mechanical properties during pyrolysis at high temperatures (415–600 °C) and high pressure (50–125 MPa) for mature to over-mature stages. The nanoindentation and in-situ AFM-QNM analysis are utilized to characterize the changes in mechanical properties during evolution. Subsequently, gas adsorption, Fourier Transform infrared spectroscopy (FTIR), and laser Raman spectroscopy (Raman) are used to investigate the factors influencing the mechanical properties of shale and the associated OM, and establish a model for the evolution of the mechanical properties. The results demonstrate that with increasing maturity, the overall Young's modulus of the bulk shale gradually increases from 42.8 GPa to 58.4 GPa for the temperature increment from 415 °C to 600 °C. During the thermal maturation process, the mesopore structure and quartz content of the shale significantly influence its mechanical properties. Young's modulus of OM shows an S-shaped trend, with variations in the micromechanical properties of OM corresponding to stages of hydrocarbon generation. In particular, two peaks of Young's modulus increase are observed during the mature and over-mature stages. In the mature stage, the aromatization of the kerogen leads to substantial detachment of aliphatic side chains and oxygenated functional groups, resulting in a higher degree of aromatization. This reduces the kerogen spacing and consequently increases the Young's modulus. In the over-matured stage, the process of aromatics condensation leads to the orientation and arrangement of aromatic rings, reducing the number of key site vacancies and crystal defects, thereby forming large aromatic clusters and significantly increasing the graphite-like structure. This study will facilitate the analysis of shale matrix deformation mechanisms at the microscale, providing a fundamental theoretical and scientific basis for shale fracturing design, exploration, and development.

The impact of pore heterogeneity on pore connectivity and the controlling factors utilizing spontaneous imbibition combined with multifractal dimensions: Insight from the Longmaxi Formation in Northern Guizhou

The heterogeneity of shale pores, a crucial factor in the occurrence and migration of shale gas, exerts a significant impact on the pore connectivity. Pores exhibiting a range of structural attributes to the complexity of pore connectivity. A comprehensive study into the impact of pore heterogeneity on pore connectivity in shale is lacking. This study aims to explore the impact of pore heterogeneity on pore connectivity in shale and the primary controlling factors of pore connectivity. Shale pore connectivity, pore structures, mineral composition, and geochemical parameters were assessed using various tests, including spontaneous imbibition, adsorption, mercury intrusion capillary pressure (MICP), focus ion beam-scanning electron microscopy (FIB-SEM), sulfur and carbon analysis, vitrinite reflectivity, and X-ray diffraction (XRD). Pore heterogeneity was quantitatively analyzed using the multifractal dimensions method. Results show that the increased heterogeneity of pore structure and surface roughness facilitating the potential for increased connectivity. The presence of well-developed micro-mesopores within the organic matter, alongside numerous disconnected and independent pores, contributes to an increase in pore heterogeneity. Micro-mesopore structures have a more pronounced impact on pore heterogeneity than macropores. The heterogeneity of the pores is predominantly influenced by variations in the PV and SSA of micro-mesopores. Furthermore, the heightened heterogeneity of pore structure (D1) and surface roughness (D2) leads to a more complex pore structure with increased roughness, promoting the potential for enhanced connectivity through additional throats and facilitating the formation of secondary microfractures. Shale cores characterized by high total organic carbon (TOC) content, porosity, and clay mineral content are conducive to improved pore connectivity. Conversely, the increase of thermal evolution maturity of shale in the over-mature stage is not conducive to the increase of pore connectivity. Thermal evolution maturity, TOC content, and clay mineral are key factors that control pore heterogeneity, further affecting the connectivity of shale pores. High pore connectivity is conducive to spontaneous imbibition capacity and the formation of hydraulic microfractures, promoting the migration of shale gas.

Molecular structure and evolution mechanism of shale kerogen: Insights from thermal simulation and spectroscopic analysis

During thermal evolution, the kerogen in shale formation undergoes significant chemical, structural and compositional changes, continuously influencing the shale storage capacity, hydrocarbon generation potential, and gas occurrence state. This study systematically examines the chemical structural changes during the thermal evolution of Longmaxi shale kerogen using hydrothermal laboratory experiments from 420 to 850 °C. Additionally, a range of characterization techniques, including Fourier Transform Infrared (FTIR) spectroscopy, Raman spectroscopy, High-Resolution Transmission Electron Microscopy (HRTEM), X-ray Diffraction (XRD), and Solid-state 13C Nuclear Magnetic Resonance (13C NMR), were employed to systematically investigate the kerogen structure and its evolution patterns. Results indicate that Longmaxi Formation kerogen comprises a large molecular carbon framework with aromatic structures, long-chain aliphatic components, and oxygen-containing functional groups. As thermal maturity reaches 2.6 %, the alignment of aromatic fringes gradually increased, with over 60 % aligning in the main direction. Throughout thermal evolution (1.9–3.2 %), fringes in the 5–10 Å range within aromatic structures peak at over 20.45 %, with fringes over 50 Å rapidly increasing from 3 % to over 15 %. Early in the thermal evolution, the long-chain aliphatic component of the kerogen decreases rapidly and part of the structure forms small aromatic rings through aromatisation. The mature to over-mature stage can be divided into three phases: 1) 1.7–2.4 % (loss of oxygen-containing functional groups), 2) 2.4–3.5 % (formation of larger aromatic structures via condensation reactions), 3) over 3.5 % (continued aggregation of aromatic rings, resulting in an increase in the length of aromatic fringes). At a macroscopic level, this induces changes in kerogen pore structure and carbonization features. This study thus provides new insights into the thermal evolution of shale kerogen, which in turn improve understanding of shale reservoirs for hydrocarbon exploitation.

Modeling of Burial History, Source Rock Maturity, and Hydrocarbon Generation of Marine-Continental Transitional Shale of the Permian Shanxi Formation, Southeastern Ordos Basin.

The Ordos Basin is characterized by abundant natural gas resources, and the marine-continental transitional shale gas of the Permian Shanxi Formation has great exploration and development potential. However, few systematic studies have focused on the burial history, thermal maturity, and hydrocarbon generation of the shale, which limits the understanding of shale gas enrichment and resource evaluation. To reveal the shale gas resource potential, we focused on the Shanxi Formation shale in the southeastern Ordos Basin. Net erosion was estimated, and then one-dimensional (1D) and three-dimensional (3D) geological models were constructed using PetroMod to simulate the burial-thermal history and hydrocarbons generated in the Shanxi Formation shale, and finally, the gas generation intensity was evaluated. The results show that four periods of uplift and erosion events have occurred in the study area since the Mesozoic, of which the erosion in the Late Cretaceous was the most severe. The burial center gradually shifted from east to northwest in the study area, and the basin reached the maximum burial depth in the Late Cretaceous and then gradually changed to a monoclinal tilted east to west after uplift and erosion. The Shanxi Formation shale reached the hydrocarbon generation threshold at 233 Ma (Ro = 0.5%), reached the oil generation peak at 200 Ma (Ro = 1.0%), and entered the high maturity stage rapidly (Ro = 1.3%). Currently, the average maturity is approximately 2.48%, which is in the overmature stage. The center of shale maturity was in the southern part of the study area before the Late Jurassic and shifted northeast in the late Early Cretaceous. Cumulative gas generated to date is 44.0 × 1012 m3, and the center of gas generation was in the middle-eastern region of the study area before the Early-Middle Jurassic and shifted northwest in the Early Cretaceous. This study provides a theoretical basis and guidance for the exploration and development of marine-continental transitional shale in the Ordos Basin.

Evolution of Pore Spaces in Marine Organic-Rich Shale: Insights from Multi-Scale Analysis of a Permian–Pennsylvanian Sample

The quantitative evolution pattern of pore space and genetic pore types along the maturation process in organic-rich shale reservoirs is unclear, which affects the assessment of shale storage capacity and petroleum production. A black shale outcrop sample from Kansas that is of Permian–Pennsylvanian age was collected and subjected to thermal simulation experiments at 10 different maturity stages to understand the pore sizes and pore types. Scanning electron microscopy (SEM) and image processing were used to characterize the full-scale pore-size distribution and volume evolution of this shale sample by combining low-temperature gas (CO2 and N2) physisorption and mercury intrusion porosimetry (MIP) in order to discuss the effects of hydrocarbon generation and diagenesis (HG&D) on pore development at different pore sizes. The study showed that the original shale sample is dominated by slit-like pores, with mainly organic matter (OM) pores distributed in 0–100 nm, intraparticle pores (Intra-P) of clays distributed in 30–100 nm, and interparticle pores (Inter-P) distributed in 100–1000 nm. With the increase in maturity or Ro, the OM pores increased gradually, and the OM pore-size distribution diverged to the two poles. In the oil generation stage, the OM pores were distributed in the range of 30–100 nm, while in the gas generation stage, the OM-hosted pores were mainly distributed in the range of 10–20 nm and 100–500 nm. Further into the over-maturity stage, the OM pores were mainly distributed in the range of 0–10 nm and >100 nm. The pore volume distribution across the whole pore sizes showed that the pore volume of low-maturity shale samples was mainly provided by 100–1000 nm (macropores), and the pore volumes of 0–2 nm, 30–100 nm and 1000+ nm pores gradually increase with increasing thermal maturity, with the final pore-size distribution having four peaks at 0–2, 30–100, 500–1000 nm, and 10–100 µm. Hydrocarbon generation mainly affects the pore volume in the 0–2 nm and 100–1000 nm intervals, with a positive correlation. The 2–30 nm and 30–100 nm pores were likely controlled by diagenesis, such as mineral transformation, illitization, and cementation during the maturation process.

Chemical and Geological Properties of Shale Gas: In Situ Desorption of Lower Cambrian Niutitang Shale in the Micangshan Tectonic Zone of South Shaanxi, China.

Shale gas was recently found in the Lower Cambrian Niutitang Formation (LCNF) of the Micangshan tectonic zone of south Shaanxi (MTZSS), but not in commercial quantities. To determine the laws governing the generation, enrichment, and desorption of shale gases in overmatured shale strata in the LCNF of MTZSS, we carried out in situ desorption experiments on nine shale core samples and got 168 desorbed gas samples at different phases of desorption. Also measured were the chemical and carbon isotopic compositions of these desorbed gas samples and the geochemical parameters of the shale core samples. CH4 was the predominant hydrocarbon shale gas identified in the 82.06-98.48% range, suggesting that the gases were mainly dry. The nonhydrocarbon gases found were CO2 and H2. The CH4 content of the desorbed gas samples dropped continuously during desorption, lowering the dryness index to 98.48 and 92.26% of the first and last desorbed shale gas, respectively. The change in the gas ratio during shale gas desorption proved that the adsorbability of the LCNF to the various gases follows the trend H2 > CO2 > C2H6 > CH4 > He. Further, δ13C2H6 and δ13CH4 become heavier during desorption, showing isotopic fractionation arising from the desorption-diffusion coeffect. As the desorption temperature increases, the value of δ13CH4 increases because 12CH4 is more sensitive to temperature than 13CH4, so it is with the ethane. Similar to the LCNF shale gas in other areas of China, the desorbed shale gases are characteristic of carbon isotope reversal (CIR) (δ13CH4 > δ13C2H6). The cracking of the residual soluble organic matter at the high overmaturity stage mixed with the cracking of kerogen at the early stage of maturation, causing CIR. Furthermore, the desorbed gas content was proportionally and inversely related to the CIR degree and final dryness index of the desorbed gas, respectively. Moreover, the carbon isotope fractionation degree of CH4 and δ13C1 of the last desorbed gas correlated positively with the desorbed gas content and the desorbed time of the gas. In conclusion, the four parameters are effective parameters for identifying shale gas sweet spots.

Controls of carbon isotope fractionation during gas desorption in overmature marine shales

Carbon isotope fractionation serves as a crucial tool for assessing gas-in-place content and the gas-adsorbed ratio of shale gas during production. However, a significant gap exists in the understanding of the mechanism and impacts of diverse composition and organic matter on carbon isotope fractionation. To address this gap, this study conducted adsorption and desorption experiments on ten shale samples from the Longmaxi Formation. Various integrated analytical techniques were employed, encompassing X-ray diffraction, bitumen reflectance measurement, total organic carbon (TOC) content analysis, stable carbon isotope analysis, low-pressure gas adsorption tests, and field emission scanning electron microscopic observations. The results reveal that methane dominates the shale gas, with the carbon isotopes exhibiting a distinctive full reversal, attributed to the redox reaction between the ethane and water or transition metals. Differential adsorption capacities of shale led to varied carbon isotope distribution during desorption experiments. Increased micropore quantity in shale is anticipated to augment its adsorption capacity, while elevated feldspar content constrains adsorption due to the absence of intraparticle pores. Consequently, a negative correlation is observed between feldspar content and shale gas fractionation. Although intraparticle pores exist in carbon minerals, their connectivity and low carbonate content limit adsorption capacity in clay-rich shale. Deep burial depletes slit pores in clay minerals, resulting in a low adsorption capacity in clay-rich shale. Notably, the over-mature stage exhibits a substantial increase in micropores within organic matter, positively correlating with carbon isotope fractionation. The positive correlation between quartz content and TOC content is attributed to the positive relationship between the quartz content and carbon isotope fractionation. Additionally, the isotopic values of desorbed gas exhibit significant variability when TOC content exceeds 2.0%, remaining stable when TOC content is less than 2.0%.

Petroleum potential from Permian-Triassic strata of the Maniamba Basin, Mozambique: A preliminary characterisation

Abstract In order to further our understanding regarding the petroleum potential of the Maniamba Basin, Mozambique, organic rich sediments from four outcrops were investigated. Organic-rich shales, claystones, sandstones and siltstones were sampled for geochemical organic analyses that included Total Organic Carbon (TOC), and Rock Eval Pyrolysis. The pyrolysis analysis showed that the TOC ranges from good to excellent, thus indicating a potential for hydrocarbon generation. Based on the hydrogen index (HI) versus oxygen index (OI) diagram, most samples were classified as kerogen type III or IV, however, a mixed type II and III was also observed. These data suggest that the Organic Matter (OM) is of terrigenous origin with the occurrence of organofacies C, CD and D. The majority of the studied samples are found to be at mature to overmature stages. The overmaturation of the OM may be associated with tectonic events during the process of basin subsidence, and close proximity to igneous intrusions. Further, an indigenous nature of the hydrocarbon has been identified. Similar organic matter properties of the studied sections are correlatable with those from Moatize Minjova, Sanangoé-Mefidezi (Mozambique), Ruhuhu (Tanzania) and the Main Karoo Basin in South Africa. Overall, the results of this study suggest a good potential for gas.

Mesozoic and Cenozoic Tectono-Thermal Reconstruction of the Southern Ordos Basin: Revealed by Apatite Fission Track and (U-Th)/He Dating

The Ordos Basin is rich in oil and gas resources in the Paleozoic strata. The southern part of the basin boasts a thick Paleozoic sedimentary sequence, enriched organic matter, favorable sedimentary facies, and hydrocarbon source rocks with an over-mature thermal evolution stage. However, the lack of in-depth study of the tectono-thermal evolution in the southern basin limits regional oil and gas exploration. In this study, drill core and outcrop samples were collected from the Shanbei Slope and the Weibei Uplift, respectively. These samples were subjected to apatite fission track (AFT) and (U-Th)/He dating (AHe). The results were used to reconstruct the thermal history of the southern basin, calculate exhumation rates, and analyze the tectonic evolution of the basin. The seven annealed AFT data values from the Shanbei Slope range from 21.4 to 52.8 Ma, with mean track lengths of 13.24 μm, and the twelve unannealed AFT data values from the Weibei Uplift range from 111.9 to 204.6 Ma. The seven AHe data values from the Shanbei Slope range from 17.0 to 31.8 Ma, and the eight AHe data values from the Weibei Uplift range from 31.7 to 47.5 Ma. The thermal history is characterized by a prolonged phase of burial and heating from the Triassic to the Late Early Cretaceous, followed by a phase of uplift and cooling that continued into the Cenozoic. This cooling phase exhibits three distinct stages with varying rates of uplift and cooling. According to the dating results, the cooling timing of the southern basin was earlier than that of the central part, and the southern basin experienced higher uplift rates during the Paleogene than in other periods of the Cenozoic. This may be attributed to the far-field effects of the collision between the Indian Plate and the Eurasian Plate during the Paleogene.

Thermal maturity evaluation on mildly artificially oxidised sporomorphs: A comprehensive calibration of palynomorph darkness index (PDI) with vitrinite reflectance

The assessment of thermal maturity of organic matter dispersed in sedimentary rocks is a fundamental task in geological studies, including the modelling of burial history of sedimentary basins, palaeotemperature evolution and the hydrocarbon generation assessment. Palynomorph Darkness Index (PDI) is a quantitative method for evaluating thermal maturity, based on the RGB image-analysis of palynomorphs. The growing use of this method has demonstrated the need for calibration against other maturity indicators such as vitrinite reflectance (Avg. VRo), Tmax, SCI (Spore Color Index) and TAI (Thermal Alteration Index). In the present study, PDI was determined on continental palynomorphs and compared with a large dataset of vitrinite reflectance measurements from the same samples, covering a thermal maturity range between the immature and overmature stages of hydrocarbon generation. The selected samples, belonging to twenty-five different wells, were previously oxidised with nitric acid (60%HNO3) for approximately 20 min to facilitate routine palynostratigraphic investigation. Calibration against vitrinite reflectance resulted in two linear correlation equations, one for Avg. VRo below 0.7% and another for values above 0.7%. Additionally, six samples from the Selli level of the Aptian Gorgo a Cerbara section (Umbria-Marche Apennine, Central Italy) were analysed to understand the differences in PDI values between artificially oxidised and unoxidised organic matter. The analysis showed a discrepancy of approximately 19% in PDI values for the same thermal maturity between unoxidised and oxidised sporomorphs. Our results confirm that PDI is a reliable and valid method for evaluating thermal maturity of organic matter, particularly when standard methods cannot be applied. Moreover, comparison with published data concerning other palynomorph groups (i.e., acritarchs) further supports the usefulness of this technique in geological investigations.

A tectono-thermal perspective on the petroleum generation, accumulation and preservation in the southern Ordos Basin, North China

The southern Ordos Basin has excellent petroleum exploration prospects. However, the tectono-thermal history and the controls on petroleum generation, accumulation and preservation conditions in southern basin are unclear. In this study, we analyzed the present geothermal field, paleo-geothermal gradient, maturity of the hydrocarbon source rocks, uplift and cooling process and tectono-thermal evolution history. In the study area, for the Ordovician, Permain and the Triassic strata, the present temperature is low (30−70 °C) in the southeastern area but high (80−140 °C) in the northwestern area. The paleo-geothermal gradient varied from 24 °C/km to 30 °C/km with a heat flow of 58–69 mW/m2 (i.e., a medium-temperature basin). The paleo-temperatures are higher than the present temperatures and the maximum paleo-temperatures controlled the thermal maturity of the source rocks. The vitrinite reflectance (Ro) values of the Triassic strata are >0.7% and the thermal maturity reached the middle-mature oil generation stage. The Ro values of the Permian-Ordovician strata are >1.8% and the thermal maturity reached the over-mature gas generation stage. The southern Ordos Basin has experienced the multiple tectonic events at the Late Ordovician Caledonian (452 Ma), Late Triassic (215 Ma), Late Jurassic (165−160 Ma), End-Early Cretaceous (110−100 Ma) and Cenozoic (since 40 Ma). A large-scale tectono-thermal event occurred at the End-Early Cretaceous (110−100 Ma), which was controlled by lithospheric extension, destruction and thinning. This event led to the highest paleo-temperatures and thermal maturities and coeval with the peak period of petroleum generation and accumulation. The southern Ordos Basin has undergone rapid and large-scale uplift since the Late Cretaceous due to expansion of the northeastern margin of the Tibetan Plateau, uplift of the Qinling orogenic belt and thrust faulting in the Liupanshan tectonic belt. The southern Ordos Basin experienced tectonic overprinting that was strong in the south and weak in the north. The strongest overprinting occurred in the southwestern part of the basin. The large-scale uplift, denudation and faulting led to oil and gas loss from reservoirs. The petroleum generation, accumulation and preservation in the southern Ordos Basin were affected by deep lithospheric structures and the tectono-thermal evolution. This work provides a novel tectono-thermal perspective on the petroleum generation, accumulation and preservation condition of the southern Ordos Basin.

Enrichment characteristics and exploration potential of the Permian marine shale gas in the Wujiaping Formation, Sichuan Basin, SW China

Shale gas exploration has achieved global success in marine shales. This study analysed geochemical, mineralogical, porosity, permeability and gas‐bearing parameters of organic‐rich shales in the Permian Wujiaping Formation in the Sichuan Basin. A comprehensive comparison was conducted with the Longtan Formation transitional shales and typical commercially developed marine shales. The results showed that: (1) siliceous shale within the Wujiaping Formation exhibits total organic carbon content ranging from 0.60% to 9.53% (average 4.45%) and vitrinite reflectance (Ro) ranging from 1.83% to 2.14% (average 1.98%), indicating an overmature stage of hydrocarbon generation. Porosity varies from 0.48% to 11.8% (average 4.94%), with an average content of 51.4% brittle minerals (quartz+calcite+dolomite) and calculating gas content exceeding 3 m3/t based on logging data. Effective sealing is achieved by the overlying carbonate of the Changxing Formation and the underlying carbonate of the Maokou Formation. (2) The primary storage space of the siliceous shale in the Wujiaping Formation encompasses diverse organic matter pores, clay mineral pores and microfractures. The porosity and permeability of the Wujiaping Formation marine shale ranges from 0.48% to 11.8% and 0.0053 to 0.8450 mD. Total gas content was estimated between 3 to 12 m3/t averaging 6 m3/t. (3) By comparing Permian Wujiaping Formation shales with Longtan Formation transitional shales, Wufeng Formation‐Longmaxi Formation shales and the typical North American marine gas shales (such as Barnett, Ohio, Antrim, New Albany, etc.), we conclude that marine siliceous shales within the Wujiaping Formation exhibit enrichment conditions comparable to established marine shales and superior to Permian transitional shales. The favourable upper and lower seals of the Wujiaping Formation resemble those of the Barnett shale gas reservoirs. In conclusion, the marine shale in Wujiaping Formation holds potential for substantial shale gas reservoirs and is poised for strategic exploration and development breakthroughs in the northeast and east Sichuan Basin.

The Effect of Thermal Maturity on the Pore Structure Heterogeneity of Xiamaling Shale by Multifractal Analysis Theory: A Case from Pyrolysis Simulation Experiments

Shale oil and gas, as source-reservoir-type resources, result from organic matter hydrocarbon generation, diagenesis, and nanoscale pore during the evolution processes, which are essential aspects of shale gas enrichment and reservoir formation. To investigate the impact of diagenetic hydrocarbons on shale pore heterogeneity, a thermal simulation of hydrocarbon formation was conducted on immature shale from the Middle Proterozoic Xiamaling Formation in the Zhangjiakou area, covering stages from mature to overmature. Nuclear magnetic resonance (NMR) instruments analyzed the microstructure of the thermally simulated samples, and the multifractal model quantitatively assessed pore development and heterogeneity in the experimental samples. The results reveal that the quartz and clay mineral contents show alternating trends with increasing temperature. Organic matter dissolution intensifies while unstable mineral content decreases, promoting clay mineral content development. Pyrolysis intensity influences Total Organic Carbon (TOC), which reduces as hydrocarbons are generated and released during simulation. Porosity exhibits a decreasing–increasing–decreasing trend during thermal evolution, peaking at high maturity. At maturity, hydrocarbon generation obstructs pore space, resulting in higher levels of bound fluid porosity than those of movable fluid porosity. Conversely, high maturity leads to many organic matter micropores, elevating movable fluid porosity and facilitating seepage. Shale pore heterogeneity significantly increases before 450 °C due to the dissolution of pores and the generation of liquid and gas hydrocarbons. In the highly overmature stage, pore heterogeneity tends to increase slowly, correlated with the generation of numerous micro- and nano-organic matter pores.

Assessment of kerogen types and source rock potential of Lower Jurassic successions in the Mandawa Basin, SE Tanzania

Variability in organic matter types and quality of source rock intervals across evolving rift-basins has been the focus of previous studies, which have shown that due to dynamic sedimentary regimes and water depths such source intervals occur sporadically and restricted to specific stratigraphic horizons. Such heterogeneous settings require detailed geochemical analysis to document variations in source quality. This study presents a comprehensive geochemical analysis of source rock intervals in Lower Jurassic successions (Mbuo, Nondwa and Mihambia Formations) in the Mandawa Basin, on-shore Tanzania, in order to constrain organic matter types and quality. Organic matter richness was measured by Total Organic Carbon (TOC) analysis, while quality and thermal maturity of organic matter was assessed by programmed pyrolysis, complemented by organic carbon isotope analysis (δ13Corg) of sediment samples collected from outcrops, cores, and cuttings samples. TOC and programmed pyrolysis datasets from existing literature were synthesized in this study to better understand organic matter quality and thermal maturity evolution on regional scale. These data were examined in relation to paleogeography to gain insight into the factors regulating the distribution of organic matter quality within the Mandawa Basin.Average TOC contents in Lower Jurassic sediments fluctuate from 0.31 to 4.83 wt% with an average of 1.4 wt%, whereas, kerogen yield (S2) and hydrogen index (HI) remain generally low, with values ranging from 0.01 to 8.6 (mg HC/g rock) with an average (0.92 mg HC/g rock) as well as from 2 to 233 (mg HC/g TOC) with an average of 46 (mg HC/g TOC), respectively. Organic matter is composed mainly of type III (gas prone) to IV (inert) kerogens with lesser admixture of type II-III kerogen (oil-gas prone), which have been deeply buried and undergone a wider range of thermal diagenesis, from early to overmature stage. The δ13Corg isotopic composition of organic matter is consistent with kerogen typing, indicating terrestrial organic matter with a heavier signature during sea level low stands. Upon marine incursions δ13Corg shifts to isotopically more depleted marine organic matter. This implies that the investigated source intervals have poor to fair source potential. Only a few intervals of limited thickness in the Upper Mbuo, Nondwa, and Mihambia Formations of the Mita Gamma-1 and East Lika-1 wells, as well as in the Lower Mbuo Formation in the Mbuo-1 well, have been locally enriched. The enrichment is attributed to periodic marine ingressions that have persisted since the Pliensbachian period and suggests the presence of oil generation potential.A comparison of TOC and programmed pyrolysis borehole data from this study to those compiled from literature in a paleogeographical context reveals high spatial variability. The southeastern and northwestern parts of the study area have the highest source potential, indicating high organic matter productivity in the dysoxic to anoxic water column, which promoted the preservation of organic matter. In contrast, the eastern and western parts generally show low source potential, indicating degraded organic matter and significant terrestrial influxes from emergent land that were deposited in shallow, mixed oxygenated water with low to moderate organic matter productivity.

The Lower Cambrian Xiaoerbulake Formation in the Tarim Basin as a potential carbonate source rock

The oil and gas exploration of the Middle and Lower Cambrian in the Tarim Basin reveals widely distributed source rocks with the Yuertusi Formation being recognized as high-quality source rocks that are distributed in a rather small range. The Xiaoerbulake Formation that is right under the Yuertusi Formation has also been eyed as potential high-quality source rocks and is studied through analyses focusing on the stratigraphic development, the abundance, type, and maturity of organic matter, and the paleoproductivity of a dark-colored algae dolomite within the formation. The results show that the dolomite is rich in organic matter of mainly types I and II kerogens. Although reached the high mature to over-mature stage, the dolomite was deposited in an anoxic sedimentary environment featuring a high paleoproductivity level and a high organic carbon burial efficiency, quite favorable for the development of high-quality source rocks. The study provides material evidence to the Middle-Lower Cambrian subsalt source rock-reservoir-caprock combination model for the Tarim Basin.

Response of resin canal area of Pinus tabuliformis with different ages to climate change in Taiyue Mountains, China.

To investigate the responses of resin canal area of Pinus tabuliformis with different ages to climate change, we analyzed the relationship between the resin canal area and climate factors from 1972 to 2017 in P. tabuliformis plantation at young age, middle age, near-mature, mature, and over-mature periods in Taiyue Mountains, Shanxi Province. The results showed that 55.7% to 75.2% of resin canal occurred in earlywood. The mature and over-mature periods had the largest resin channel area, sequentially followed by near mature, middle age, and young age periods. Annual mean latewood resin canal area increased significantly in near-mature period and mature period, but not in other periods. There was a significant negative correlation between earlywood resin canal area and minimum temperature during the growing season (May to July) for trees at middle age period. Earlywood resin canal area of mature trees showed significant negative correlation with minimum temperature during the growing season, but significant positive correlation with drought (PDSI) in the non-growing season (previous September to current April). The total area of earlywood resin canal at the young, near-mature, and mature periods was less influenced by climate than other periods. The minimum growing season temperature was a limiting factor to earlywood resin canal growth, while the non-growing season drought gradually became a limiting factor for earlywood resin canal with increasing tree age. The total area of earlywood resin canal decreased with increasing non-growing season drought and increasing growing season minimum temperature. In the context of global warming, the earlywood resin canal area may gradually decrease at all five periods, and the most reduction in the over-mature stage.

Biostratigraphy, organic petrography and carbon isotope chemostratigraphy of the Ordovician-Silurian black shales from the Northwestern Domain of Peninsular Malaysia

Integrated biostratigraphy, petrography, organic carbon and carbon isotope chemostratigraphy were used in tandem to assess the paleoenvironment and hydrocarbon potential of the latest Ordovician to Early Silurian basin in the Northwestern Domain of Peninsular Malaysia. Graptolite biostratigraphy indicated a Hirnantian to Aeronian age for the Tanjung Dendang Formation in Pulau Langgun, Langkawi. The graptolite fauna from the Langkawi Islands demonstrates a close association with the South Chinese fauna. The graptolite fragments show a non-granular surface morphology and are mostly present in a long, stipe-like, lath shape when observed under reflected white light microscopy. The pyrites present are relatively small and sparse during the latest Ordovician, suggesting a euxinic condition, but during the Silurian, the pyrites are larger and more common, suggesting anoxic and later dysoxic bottom water. The mean random reflectance of non-granular graptolite in sections perpendicular to the bedding range from 1.8% to 3.07%, and the equivalent vitrinite reflectance ranges from 1.86% Ro to 3.12% Ro, suggesting an overmature stage in term of hydrocarbon generation. The TOC of the Langkawi black shale averages 2.1 wt%, while the rock from the Mahang and Sungai Petani areas measures 1.37 wt% and 0.47% wt%, respectively. δ13Corg chemostratigraphy for the Tanjung Dendang Formation resulted in δ13Corg level between −31.4 ‰ to −28.7 ‰. The Hirnantian Isotope Carbon Excursion (HICE), signalled by a high δ13Corg value, is documented near the base of the formation, followed by a sudden negative shift towards the Ordovician-Silurian boundary. δ13Corg more or less maintained during the Silurian except for slight carbon excursion events during the middle Rhuddanian and early Aeronian. The δ13Corg excursion events from the Tanjung Dendang Formation in Langkawi can be accurately correlated with successions from China, the United Kingdom and Artic Canada.

Biomarkers applied to the assessment of organic matter sources, thermal maturation and depositional environment of the Devonian Pimenteiras Formation, Parnaíba Basin (Brazil)

The potential for hydrocarbon generation of Devonian shales from Pimenteiras Formation has been the object of study in many research works. In this study, the focus is to evaluate the organic matter sources, thermal maturation and depositional environments of the Pimenteiras Formation based on aliphatic and aromatics biomarkers. Thereby, a total of 30 samples from three wells were analyzed using gas chromatography and mass spectrometry (GC/MS). The n-alkanes, isoprenoids, and terpanes data revealed that shales from Pimenteiras Formation results of a mixture of marine, transitional and terrestrial organic matter. These findings are consistent with C27, C28 and C29 steranes distribution and abundance of methylphenanthrene and methyldibenzothiophene. The Pr/n-C17 and Ph/n-C18 ratios in the BP-77 well are greater than 1.0 (immature), while the most samples from BP-59 and BP-22 wells, the Pr/n-C17 and Ph/n-C18 ratios are less than 1.0 (mature). Findings are consistent with CPI, M30/H30, S/(S + R) (C29 ααα) and C29 ββ/(αα+ββ ratios. Additionally, the Ts/(Ts + Tm) ratios, MPI-1 versus Ro, 2-MP, 3-MP, MPI-1, MPR-1, dimethylnaphthalenes and dimethyldibenzothiophene indicate that the organic matter varies from immature to mature, and reaches the overmature stage in terms of thermal maturity. The Pr/Ph ratio, Pr/n-C17 vs Ph/n-C18 plot, high H35/H34, C29/C30, C27 Dia/C27 ααα (R + S) ratios and high concentration of dibenzothiophene suggests that the organic matter was deposited under oxic, suboxic and anoxic conditions. On the other hand, the low abundance of gammacerane and low Gam/H30 ratio suggests a low salinity and/or water column stratification. Additionally, the data showed that the organic matter was deposited in marine, marine carbonate platform and terrestrial environments.