Thermal Maturity Research Articles

Evolution of pore structure and diagenetic stages of late Permian shales in the Lower Yangtze Region, South China

This study examines the evolution characteristics of shale pores in the Late Permian Longtan Formation located in the Lower Yangtze region of South China. The complete process of thermal evolution of the samples was achieved through thermal simulation experiments while identifying qualitatively the pore types and their development characteristics using field emission-scanning electron microscope (FE-SEM). Quantitative analysis of pore size distribution was conducted through mercury intrusion capillary pressure (MICP), nitrogen (N2) and carbon dioxide (CO2) adsorption experiments. The paper comprehensively analyzed the pore evolution characteristics and controlling factors of shale in the study area, with an analysis of diagenetic differences. Findings reveal that during the pore evolution process, both morphology and pore size are influenced by thermal maturity. The pore volume is dominated by mesopores and macropores, while the specific surface area is mainly dominated by mesopores and micropores. Thermal evolution promotes the formation of micropores and mesopores but hinders the development of macropores. Moreover, clay minerals transformation and mineral dissolution make certain contributions to the development of micropores. The diagenesis in the study area is controlled primarily by the pyrolysis of organic matter. Pyrite and clay minerals are the first to dissolve, followed by calcite and quartz. Five stages of evolution characterization have been identified from low-mature stage (Ro = 0.88 %) to overmature stage (Ro = 3.35 %) in combination with diagenesis. The development of pore structure and its influencing factors vary across different stages. The influencing factors mainly include hydrocarbon generation from organic matter, compaction, mineral transformation, and dissolution. The process of hydrocarbon generation in organic matter occurs throughout the entire pore evolution process, resulting in the development of numerous micropores and mesopores. Compaction primarily impacts pore development during the early diagenetic stage, causing a substantial transition of primary mineral pores from macropores to mesopores. Mineral transformation and dissolution take place during and after the middle diagenetic stage. The former governs the development of mesopore-sized clay interlayer pores, while the latter primarily generates micropores.

Acritarch Palynomorph Darkness Index (PDI) as an indicator of thermal maturity in Silurian sections from Saudi Arabia

Palynomorph Darkness Index (PDI) measurements on acritarchs from Silurian strata in Saudi Arabia exhibit an irregular but potentially useful relationship to other vitrinite reflectance proxies. Four distinct stages in PDI evolution can be recognized with thermal maturity. In Stage 1, acritarch PDI is <10% and shows no increase with increasing maturity. A very rapid increase in PDI towards the end of the oil window from <10% to ca. 25% characterises Stage 2, which is followed by a gradual increase in Stage 3 from ca. 25% to approximately 80%. PDI Stage 4 is represented by postmature rocks, with acritarch PDI >82% and showing little change with increasing maturity. Acritarch fluorescence is totally extinguished within the oil window.

Facies distribution, paleoenvironment and hydrocarbon potential of Kanawa Member of Pindiga Formation, Gongola Basin, Northern Benue Trough, Nigeria

The Gongola sub-basin is a frontier inland sedimentary basin consisting of Cretaceous to Tertiary sediments, believed to have been deposited in continental to coastal shallow marine complex. The Kanawa Member of Pindiga Formation is a sequence of limestone and shale. Sedimentology, facies analysis, biostratigraphy, thermal maturity assessment and kerogen typing were conducted on these strata to determine the facies, facies associations, facies successions, paleoenvironment, age, and hydrocarbon generation potential. The studied sequences are of Turonian–Santonian age, deposited due to a major transgression of the basal part of the Pindiga Formation. The shale-limestone series of the Kanawa Member is interpreted as lagoon-to-shallow marine deposits of a carbonate ramp depositional system. The sediments consist of mainly wackestone and packstone facies and shallow marine foraminiferal, suggesting that the Kanawa Member was deposited under low-energy condition. The presence of Ammobaculites subcretacea, Haplophragmoides bauchensis, Haplophragmoides pindigensis, Haplophragmoides excavata, Ammobaulites pindigensis, Ammobaculites bauchensis, Ammobaculites gombensis, Ammobaculites benuensis Ammoastuta nigeriana, Reophax guineana and Miliammina pindigensis foraminiferal assemblages, indicating Late Cretaceous age. Hydrocarbon potential is interpreted to be gas prone although, minor oil could be expected. These correspond to temperature range (TAI values) of 60 to 75 indicating thermally matured for both oil and gas generation.

BIOSTRATIGRAPHY, PALEOENVIRONMENT AND HYDROCARBON POTENTIAL OF FIKA MEMBER OF PINDIGA FORMATION, GONGOLA SUB-BASIN, NORTHERN BENUE TROUGH, NE NIGERIA

The Fika Member, a crucial stratigraphic unit within the Pindiga Formation, represents a significant geological entity with substantial implications for understanding the regional paleoenvironmental evolution and hydrocarbon prospectivity. This study integrates biostratigraphic analyses, sedimentological investigations, and hydrocarbon potential assessments to elucidate the depositional history, paleoenvironmental conditions, and source rock prospect of the Fika Member. Facies and their stratigraphical distribution analyses were conducted on the Fika Shale exposed mainly at Gabukka Stream 1 and 2. Twenty (20) samples collected were subjected for standard palynological and foraminifera analyses. A standard method of palynomorphs extraction that involves the use of Hydrofluoric and Hydrochloric acid was employed. For foraminifera analysis, washing and sieving method was used. It was discovered that agglutinated foraminifera are the dominance taxa in ten (10) out the twenty (20) samples studied. Based on the colours of the agglutinated foraminiferal and Foraminiferal Color Index (FCI) values suggest low thermal maturity for both oil and gas generation. The foraminiferal assemblages indicate marginal marine (fluvio marine) to shallow inner neritic environments. This is supported by the sedimentological data which indicates a shallow marine depositional environment. The biostratigraphic data suggest Santonian age for the Fika Member.

Evaluation of thermal maturity of source rock based on geochemical method, a case study of Late Oligocene source rock in Hoa Tra field, Cuu Long basin, Vietnam

The &amp;nbsp;Hoa Tra field is located in the southeast of the Cuu Long basin which has great potential for oil and gas. The source rocks in this area are mainly fine-grained sediments from the late Oligocene and early Miocene, which are located in a continuous deposition zone and under anaerobic conditions. This paper focuses on studying the maturity level of late Oligocene source rock through geochemical analysis methods. Specifically, the paper uses indicators such as T­,&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt;, MPI-1, T&lt;sub&gt;s&lt;/sub&gt;/(T&lt;sub&gt;s&lt;/sub&gt;+T&lt;sub&gt;m&lt;/sub&gt;) and C&lt;sub&gt;29&amp;nbsp;&lt;/sub&gt;steran 20S/(20S+20R) from Rock-Eval Pyrolysis, Vitrinite reflectance and Gas chromatography-Mass spectrometry methods, respectively, to evaluate the level of thermal maturity of the source rock. The source rocks in the Hoa Tra field mainly contain types I and II, which are poor in vitrinite particles, leading to low&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt; measurement results. However, when&amp;nbsp;R&lt;sub&gt;o&lt;/sub&gt; is calculated from T&lt;sub&gt;max&amp;nbsp;&lt;/sub&gt;and (MPI-1), it indicates that the thermal maturity of source rock from the upper part of the late Oligocene is in the early mature stage (R&lt;sub&gt;o avg&lt;/sub&gt;= 0.56%), while those from the lower part of late Oligocene are mature and in the phase of oil generation (R&lt;sub&gt;o avg&lt;/sub&gt;= 0.65%). These results are similar to those obtained from assessing thermal maturity using T&lt;sub&gt;s&lt;/sub&gt;/(T&lt;sub&gt;s&lt;/sub&gt;+T&lt;sub&gt;m&lt;/sub&gt; and&amp;nbsp;C&lt;sub&gt;29&amp;nbsp;&lt;/sub&gt;20S/(20S+20R) indicator (the average values for the respective parameters are 0.32 and 0.31 for the upper part, while those are 0.39 and 0.42 for the lower part of late Oligocene). The article also shows that the contribution to the &amp;nbsp;Hoa Tra field is not only from in-situ generated oil but also from migratory oil coming from nearby troughs.

Shale gas potential evaluation based on well-logs and basin modeling of the Cretaceous-Paleocene succession of the Kohat Plateau, Pakistan: implication for shale gas exploration

This study examines subsurface data from three wells to assess the shale gas potential of the Cretaceous-Paleocene succession of the Kohat Plateau, Pakistan. The petrophysical analysis was performed to calculate total organic carbon (TOC) using the Passey model. Petro-elastic parameters (Poisson ratio, Young modulus, and brittleness) and thermal maturity were also evaluated, respectively. The average TOC values in Makori-01 (as calculated by Passey's method) are 2.88 (wt%) for the Lockhart Limestone and 2.10 (wt%) for the Chichali-1 Formation. In Manzalai-02 well, the Lockhart, Hangu, Kawagarh, Lumshiwal, and Chichali formations TOC values are 2.81 (wt%), 2.55 (wt%), 2.32(wt%), 2.29 (wt%) and 2.20 (wt%) respectively. To exploit the unconventional resources, zones I and II in the Sumari Deep X-01 well (Chichali Formation) with an average TOC value of 2.71 (wt%) can be considered favorable areas for further evaluation. The volume of shale value is resulted as maximum within Chichali Formation in Makori-01 (58.52–75.89%), Manzalai-02 (54.09%), and Sumari Deep X-01 (70.47%), while the least value is noted within Lockhart Limestone in Makori-01 (12.25%) and Manzalai-02 (14.02%), and in Hangu Formation in Sumari Deep X-01 (12.39%). Also, the elastic properties reveal two to four zones of Young modulus, brittleness index, and Poisson’s ratio within the Chichali Formation in the studied three wells. The isopach maps show that the Patala, Lockhart, Hangu, Lumshiwal, and Chichali formations in the research area exhibit variable thicknesses. The 1D maturity models of the Makori-01 and Manzalai-02 wells indicate burial to a depth of 8 km approximately 2.5 Ma ago and the apex of oil production (1.1% Ro). The 1D maturity models indicate that the Sumari Deep X-01 well has encountered minimal burial (in terms of both time and depth) and, as a result, exhibits minimal potential source rock intervals. The volumetric estimate of unconventional recoverable gas resources is approximately 1.57 TCF in the study area. The integrated research provides the basis for tracking and assessing the unconventional resource potential, distribution, and characteristics within the studied basin.

Opening and Post-Rift Evolution of Alpine Tethys Passive Margins: Insights from 1D Numerical Modeling of the Jurassic Mikulov Formation in the Vienna Basin Region, Austria

This study employed 1D numerical pseudo models to examine the Upper Jurassic carbonate succession, focusing on the Mikulov Formation in the Vienna Basin region. It addresses the protracted and complex history of the Jurassic source rock play, revealing a transition from rapid syn-rift (&gt;200 m/Ma) to slower post-rift sedimentation/subsidence of the overlying layers during extensional deformation (up to 120 m/Ma with a thickness of 1300 m). This provides valuable insights into the rift-to-drift stage of the central Alpine Tethys margin. The Mikulov marls exhibit characteristics of a post-rift passive margin with slow sedimentation rates. However, a crustal stretching analysis using syn-rift heat flow sensitivity suggested that thermal extension of the basement alone cannot fully explain the mid-Jurassic syn-rift stage in this segment of the Alpine Tethys. The sensitivity analysis showed that the mid-late Jurassic differential syn-rift sequences were exposed to slightly cooler temperatures than the crustal stretching model predicted. Heat flow values below 120 mW/m2 aligned with measurements from deeply settled Mesozoic successions, suggesting cold but short gravity-driven subsidence. This may account for the relatively low thermal maturation of the primary source rock interval identified by the time-chart analysis, despite the complex tectonic history and considerable sedimentary burial. The post-Mesozoic changes in the compaction trend are possibly linked to the compressional thrusting of the Alpine foreland and postdating listric faulting across the Vienna Basin.

Insights on Using Solid Bitumen Reflectance as a Thermal Maturity Proxy in the Bakken Formation, Williston Basin, USA.

To further refine the use of solid bitumen reflectance (BRo in %) as a measurement of thermal maturity in source-rock reservoirs, we examined its relationship to other thermal proxies in the Bakken Formation. Comparisons included criteria from programmed temperature pyrolysis, gas chromatography (GC), and Fourier transform infrared (FTIR) spectroscopy. Thirty-two organic-rich samples from the lower and upper shale members of the Devonian-Lower Carboniferous Bakken Formation were collected from eight cores across the Williston Basin, USA, at depths (∼7575-11,330 ft) representing immature through post peak oil/early condensate thermal maturity conditions based on proximity to current hydrocarbon production. Unmodified BRo values were correlated to programmed temperature pyrolysis parameters (hydrogen index, production index, and T max), normal hydrocarbon and isoprenoid analysis of extractable organic matter (pristane/n-C17 and phytane/n-C18) from GC analysis, and peak ratios from FTIR spectroscopy (branching ratio and A-factor). Strong correlations between unmodified BRo values (not corrected to a vitrinite reflectance equivalent, VRe) and other thermal proxies suggest that BRo can be used as a direct thermal proxy in marine Paleozoic source-rock reservoirs where vitrinite is rare or absent. Moreover, an apparent overestimation of VRe at the lowest thermal maturity investigated herein may argue against the application of BRo conversion to VRe in the Bakken Formation. Solvent extraction caused a consistent decrease in BRo when average post-extraction values from a given well were compared to BRo prior to extraction, although the decrease in mean value was not statistically significant. These results are discussed in the context of advocating for the use of unmodified BRo values as a best practice for thermal maturity determination in Paleozoic marine source-rock reservoirs.

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.

The origin and migration laws of hydrocarbons in uranium‐bearing Luohe Formation, Pengyang area, SW Ordos Basin

The hydrocarbon activity in Pengyang area, situated in the southwestern Ordos Basin, is notably prominent. Investigation on the migration laws of hydrocarbons is imperative for comprehending the involvement in uranium mineralization. Based on the analysis of spatial distribution of hydrocarbon containing fluid and hydrocarbon generation conditions of sandstone in the Luohe Formation, the organic geochemical characteristics including hydrocarbon components, carbon isotopes and biomarker compounds were analysed. The research results indicate that: (1) hydrocarbon fluid activities in the Luohe Formation are predominantly observed in layers exhibiting higher uranium mineralization. The mudstone of the Luohe Formation had low organic matter content and low thermal maturity, which was not conducive to hydrocarbon generation. (2) Hydrocarbon‐containing fluid in the sandstone of Luohe Formation not only contained reducing gases such as methane and hydrogen but also chloroform asphalt components. The carbon isotopes of hydrocarbon in sandstone inform Luohe Formation resemble oil and gas in the Mesozoic. The biomarker parameter inferred that the parent rock of hydrocarbons in the Luohe Formation was formed under reducing and freshwater conditions, and hydrocarbon generation occurred at the mature stage. As above mentioned, a comparison was carried out between the affinity of hydrocarbon‐containing fluid in the Luohe Formation and different layers of hydrocarbon source rocks. The migration behaviour of hydrocarbon‐containing fluid in the Pengyang area has been summarized, and the involvement of hydrocarbon‐containing fluid in uranium mineralization has been discussed. The main concepts are as follows: the sedimentary environment and thermal evolution conditions of hydrocarbons in the sandstone of Luohe Formation resemble those of the primary hydrocarbon source rocks in the Yanchang Formation. The main hydrocarbon charging events in the Luohe Formation occurred before the Late Cretaceous period, which is primarily related to two hydrocarbon generation events from 130 to 100 Ma in the Yanchang Formation and fault conduits connecting the Triassic to the Cretaceous Strata. The hydrocarbon‐containing fluid released from Yanchang Formation migrating to the Luohe Formation provides reducing conditions for the precipitation of uranium in oxygen‐bearing water bodies.

Microstructural BIB-SEM investigation of Upper Cretaceous Jordanian carbonate-rich oil shales bearing type II-S kerogen

AbstractIn this study, we use Broad Ion Beam polishing and Scanning Electron Microscopy (BIB-SEM) to characterize the microstructure of selected core samples of immature Upper Cretaceous carbonate-rich oil shales from Jordan and to link the observations to porosity and compositional and geochemical data. The aim of this study is to understand the distribution of pore space, primary organic matter, and organic sulfur on a sub-micron scale, particularly in carbonate- and silicate-dominated layers. The thermal maturity of these marine carbonate mudstone samples of pelagic origin was found to be influenced by the elevated sulfur contents in these Type II-S kerogen source rocks. This was confirmed through both organic geochemistry and BIB-SEM observations, which revealed high sulfur content. Porosity in the carbonate mudstone exists within foraminifera, and aggregates of microfossil fragments. Initially, these voids provided significant inter- and intra-particle porosity which were later filled by organic matter during diagenesis. This ‘mobile’ organic matter is interpreted as microscopic bitumen, which exists as a solid or highly viscous fluid at surface conditions. It is likely a residue of low-temperature (“early”) bitumen generation. By examining the samples before and after dichloromethane (DCM) extraction and subsequent BIB-SEM analyses, we observed that the specimens contained a significant amount of soluble organic matter (SOM), mostly present in the micropores associated with calcite. The microscopic solid bitumen is observed to remain stable even under various conditions, such as in vacuum oven conditions of 105 °C (24 h), or exposure to ultra-high vacuum, broad ion beam (heat &gt; 70 °C) and an electron beam of 15 keV. This suggests that the solid bitumen acts as a solid at elevated temperatures and confining pressures (85 °C and 250 MPa), and its presence can lead to the buildup of significant fluid overpressures. Our observations indicate that the pores associated with calcite provide high storage capacity in the shales during the early stages of hydrocarbon generation. In contrast, it suggests that siliciclastic-rich samples are more prone to hydrofracturing as the (early) generated hydrocarbons cannot be expelled easily. These findings highlight the complex distribution and behavior of pore space, organic matter, and sulfur in shales, shedding light on their potential for hydrocarbon generation and storage. Graphical abstract

Experimental investigation of hydrocarbon generation, retention, and expulsion of saline lacustrine shale: Insights from improved semi-open pyrolysis experiments of Lucaogou Shale, eastern Junggar Basin, China

The organic-rich shale deposited in a saline lacustrine setting contributes massive conventional and unconventional petroleum reserves. However, the hydrocarbon generation, retention, and expulsion of saline lacustrine shale with increasing thermal maturity were rarely reported. Predicting the quality and quantity of generated, retained, and expelled hydrocarbons under various maturity stages for a given shale before drilling persists as a vital issue in exploration. Here, this study conducted two improved semi-open pyrolysis experiments to investigate the characteristics of the hydrocarbon generation, retention, and expulsion of Lucaogou Shale. Solid residues, adsorbed oil, free oil, expelled oil, and hydrocarbon gases were carefully quantified during the pyrolysis experiments. The results reveal that the composition and quantity of generated hydrocarbons are determined by the maturity and degree of openness of the shale system. The Tasmanites of Lucaogou Shale rapidly were converted to abundant oil in the main oil stage, promoting oil retention and expulsion. Meanwhile, the yield of adsorbed and free oil reached its peak at the VRo of 1.01 %. In the late oil window, the previously retained oil was further expelled from the shale as thermal stress increased. High oil retention significantly promoted the generation of extensive wet gas due to secondary cracking within the gas window. However, in a more open system, most of the generated oil was expelled within the oil window. The Lucaogou Shale generates relatively small amounts of hydrocarbon gas through kerogen cracking within the gas window. Hence, the extent of oil transformation into gas is controlled by the residence time and quantity of retained oil in shale. In addition, the maturity range of the oil saturation index greater than 100 mg oil/g TOC in Lucaogou Shale is relatively wide (VRo of 0.9 %-1.5 %), consistent with the renowned Woodford Shale. Expanded geochemical data of natural shale and artificial maturation experiments indicate the distribution of potential hydrocarbon resources. These valuable insights enhance the possibility of searching for commercial shale oil and conventional hydrocarbon resources. Collectively, these findings provide critical new insights into the hydrocarbon generation, retention, and expulsion of saline lacustrine shale, and the results could be a valuable analog for other saline lacustrine petroleum systems worldwide.

Level of thermal maturity estimation in unconventional reservoirs using interval inversion and simulating annealing method

AbstractThis study presents a novel geophysical approach for estimating the level of thermal maturity (LOM) in unconventional hydrocarbon reservoirs using well log data. LOM is a crucial parameter for assessing the hydrocarbon generation potential of source rocks, but it traditionally relies on laboratory measurements of core samples, which can be time-consuming and costly. The proposed method combines two techniques: interval inversion for estimating total organic carbon (TOC) content from well logs and simulated annealing (SA) optimization for deriving LOM from the estimated TOC. The interval inversion method enables accurate TOC estimation by jointly interpreting multiple well logs over depth intervals, overcoming limitations of conventional point-by-point inversion. Using the estimated TOC, the SA algorithm optimizes an energy function related to Passey's empirical TOC-LOM relationship, iteratively finding the optimal LOM value that best fits the well log data. This approach provides a continuous in situ LOM profile along the borehole without requiring core measurements. The effectiveness of the method is demonstrated through case studies on datasets from the North Sea (Norway), the Pannonian Basin (Hungary), and the Kingak Formation (Alaska). The LOM estimates show good agreement with reported maturity levels and allow reliable reservoir characterization. Statistical analysis confirms the robustness and accuracy of the results. By reducing dependence on core data, this integrated inversion-optimization workflow streamlines the reservoir prospecting phase, enhancing operational efficiency. The method holds promising applications across diverse geological settings for cost-effective evaluation of unconventional hydrocarbon plays.

Assessment of the source rock potential in the Sirka and Giddi collieries of South Karanapura coalfield, Jharkhand, India: Insights from megaflora, palynology, and geochemistry

Permian deposits in the Indian Peninsula have long been a significant source of coal and have great potential for hydrocarbon exploration. Here we present results of megafloral, palynological, and geochemical analysis of the Late Artinskian-Kungurian sediments in the South Karanpura coalfield to assess hydrocarbon generation potential, kerogen types, depositional settings, and thermal maturation. The results suggest anoxic to oxic depositional environments with fluctuating water levels, influenced by terrestrial inputs. The Sirka colliery is considered to be most favorable for hydrocarbon generation due to the palaeodepositional setting dominated by flooded palaeomires. The dominance of degraded organic matter and the rarity of opaque phytoclasts suggest type II/III to type III kerogen material in the palaeomire of the Srika succession, characterized by low-energy dysoxic to anoxic conditions. The thermal maturation values (Tmax 429℃) and the production index (0.01–0.02) indicate that the Sirka area has immature kerogen, but the Giddi colliery has a relatively higher Tmax (average 435℃) placing the studied sample within the mature zone. However, due to deposition in the oxidized swamp, Giddi C has poor potential for hydrocarbon generation, showing that type III/IV material has charcoal input into the sediments. Our findings contribute to global knowledge of coal formations’ oil and gas storage capacity, which has implications for energy resource assessment and exploration strategies.

Shale gas‐bearing capacity and its controlling factors of Wufeng–Longmaxi formations in northern Guizhou, China

Great progress has been made in marine shale gas of Wufeng–Longmaxi formations in the Sichuan Basin. However, shale gas exploration in the complex structural belt around the Sichuan Basin still faces great challenges. In this study, shales of Wufeng–Longmaxi formations collected from the northern Guizhou were taken as the studied target, organic matter (OM) characteristics, mineral composition, pore structure, methane adsorption capacity and in situ desorption gas content were measured, and the controlling factors of shale gas content were further discussed. The results indicated that the sedimentary facies of Wufeng–Longmaxi formations in north Guizhou varies from shallow‐water shelf facies to deep‐water shelf facies from south to north, and organic‐rich shales are primarily distributed in Daozhen‐Xishui areas, with a maximum thickness of about 80–100 m. Organic‐rich shales are characterized by high total organic carbon (TOC) content, high thermal maturation and type I–II1 kerogens, which can be comparable with those in commercially produced shale gas field in Sichuan Basin. High‐quality shale gas reservoirs generally have a high content of brittle minerals, making them easier to be fractured. OM pores are the dominanted pore type in the studied shales, followed by intergranular pores associated with brittle minerals, dissolution pores within carbonate grains and microcracks, while clay mineral‐related pores are poorly developed. The Wufeng–Longmaxi Formation shales generally have strong methane adsorption capacities, but these vary greatly across different areas. Shale gas adsorption capacity is primarily controlled by TOC content and thermal maturation level. Similarly, total gas content, including desorption gas and lost gas, varies greatly in different areas, and it is obviously lower than that in Fuling and Luzhou shale gas field, due to the loss of shale gas and low‐pressure coefficient in the complex structural zone. It is worth explaining that shale gas is not always low in northern Guizhou, which is determined by burial depth and the distance of great fractures. Shale gas content is relatively high in LY1 well and DY1 well in Xishui‐Daozhen area, and it is extremely low in TY1 well and AY1 well in Tongzi‐Zheng'an area. Shale gas content in the same structural unit is primarily influenced by TOC content, OM pore development degree and water saturation. However, different structural units have different shale gas contents, due to the differences in preservation conditions. Shale reservoirs with good preservation conditions, that is, wide and gentle structure, far from a large fault and great burial depth, generally have high shale gas contents.

Influence of thermal intrusion on the Alum Shale from south central Sweden

This study investigates the geochemical and petrological characteristics of solid bitumen in the DBH15/73 core from the Furongian (upper Cambrian) and Miaolingian (middle Cambrian) Alum Shale in Billingen, south central Sweden. At Billingen a > 30 m thick Permian diabase (dolerite sill) intruded approximately 100 m above the Alum Shale that promoting the formation of solid bitumen in the uppermost half of the Alum Shale due to enhanced heat flow. The bitumen has been classified into bituminite/diagenetic solid bitumen (DSB), initial-oil solid bitumen (IOSB), and primary-oil solid bitumen (POSB) based on their genesis, morphology and random solid bitumen reflectance (BRo). The Miaolingian shale, constituting the lower part of the Alum Shale, is immature and contains solely bituminite and DSB, with measured BRo ranging from 0.40% to 0.48%. In contrast, the Furongian shale exhibits enrichment in IOSB and POSB and range from marginally mature to peak oil generation with towards the top of the section. Characteristics of uneven heating is seen in the IOSB (BRo: 0.97–1.08%) including oxidation rims and abnormally high maturity surrounding fractures. The POSB (BRo: 0.63–2.01%) is present not only in the Alum Shale but also in the overlying Ordovician Latorp limestone and the underlying Kakeled Limestone Bed, and shows flow structures which is further evidence for migration. The abundance of POSB and IOSB is determined through maceral point counting, revealing POSB as the dominant bitumen type (1.54–7.13 vol%), while IOSB constitutes the minority (0.05–0.31 vol%) within the Furongian shale. This distribution suggests rapid thermal evolution of organic matter within the oil generation window. Additionally, a reduction in free hydrocarbons (Rock-Eval S1), potential hydrocarbons (Rock-Eval S2), and unexpectedly low Tmax was observed in the Furongian shale. Results indicate that hydrocarbon generation resulting from thermal intrusion contributes to the relatively low S2. Migration of POSB and generated oil to adjacent layers leads to the loss of S1, while the reduced Tmax may be attributed to high uranium content which weakens carbon chain bond energy. These anomalies result in an underestimation when evaluating thermal maturity and kerogen type conversion based on Rock Eval data alone.

Utica/Point Pleasant brine isotopic compositions (δ7Li, δ11B, δ138Ba) elucidate mechanisms of lithium enrichment in the Appalachian Basin

Global Li production will require a ∼500 % increase to meet 2050 projected energy storage demands. One potential source is oil and gas wastewater (i.e., produced water or brine), which naturally has high total dissolved solids (TDS) concentrations, that can also be enriched in Li (>100 mg/L). Understanding the sources and mechanisms responsible for high naturally-occurring Li concentrations can aid in efficient targeting of these brines. The isotopic composition (δ7Li, δ11B, δ138Ba) of produced water and core samples from the Utica Shale and Point Pleasant Formation (UPP) in the Appalachian Basin, USA indicates that depth-dependent thermal maturity and water-rock interaction, including diagenetic clay mineral transformations, likely control Li concentrations. A survey of Li content in produced waters throughout the USA indicates that Appalachian Basin brines from the Marcellus Shale to the UPP have the potential for economic resource recovery.

Petrological evaluation of changes occurring in organic matter sourced from Patala-Chichali sequence, Upper Indus Basin

This study focuses on the determination of organic matter (OM) concentration, thermal maturity assessment, and source rock quality of the samples from the Chichali and Patala formations. The TOC in the Chichali and Patala formations sediment samples ranged from 0.8% to 2.1% and 2.3% to 3.8% respectively, showing the sediments with different level of organic richness. The genetic potential varied from 2.4 to 17.1 mg/g, and 25.2 to 31.1 mg/g indicating the likely source rock quality. The Tmax, ranging from 306 °C to 432 °C, 413 °C and 430 °C indicating immature to mature OM. The HI values varied from 113 to 257 mg/g, 353 to 431 mg/g, OI ranged from 7 to 33 mg/g, 9 to 19 mg/g, revealing OM richness. PI assess the potential productivity of source rocks, ranged from 0.5 to 0.7, 0.6 of Chichali and Patala formations, respectively. The various geochemical properties of the Chichali and Patala formations exhibited their varying geological potential. These findings add to a better knowledge of the geological properties of the Upper Indus Basin and provide significant recommendations for hydrocarbon exploration and resource estimation.

Raman spectroscopy of Ryugu particles and their extracted residues: Fluorescence background characteristics and similarities to CI chondrites

AbstractWe present here an investigation of Ryugu particles recovered by the Hayabusa2 space mission and their extracted carbonaceous acid residues using Raman spectroscopy. Raman parameters of Ryugu intact grains and their acid residues are characterized by broad D (defect induced) and G (graphite) band widths, indicating the presence of polyaromatic carbonaceous matter with low thermal maturity. Raman spectra of Ryugu particles and CI (type 1) chondrites exhibit stronger laser‐induced fluorescence backgrounds compared to Type 2 and Type 3 carbonaceous chondrites. The high fluorescence signatures and wide bandwidths of the D and G bands of Ryugu intact grains are similar to the Raman spectra observed in CI chondrites, reflecting the low structural order of their aromatic carbonaceous matter, and strengthening the link between Ryugu particles and CI chondrites. The high fluorescence background intensity of the Ryugu particles is due to multiple causes, but it is likely that the relative abundance of geometry‐bearing macromolecular organic matter in total organic carbon contents makes a large contribution to the fluorescence intensities. Locally observed high fluorescence in the acid‐extracted residues of Ryugu is due to nitrogen‐bearing outlier phase. The high fluorescence signature is one consequence of the low degree of thermal maturity of the organic matter and supports evidence that the Ryugu particles have escaped significant parent body thermal metamorphism.

Thermal evolution differences of reservoir bitumen and their implications: A case study of the Moxi area in the central Sichuan basin

Temperature and time were generally considered as the two key influences on the thermal evolution of both source organic matters and secondary hydrocarbon products (i.e., oil, gas, bitumen and solid bitumen). And for the hydrocarbons, other factors such as the types of source organic matters, the alteration reactions and fluid pressure evolution can also influence their degree of thermal maturation. As a consolidated product of bitumen, the traditional view is that the solid bitumen originated from the same source would exhibit similar maturity after experiencing identical paleo-temperature. However, things need to be more thoughts, such as the impact of system open or not on the solid bitumen thermal evolution and maturation degree. In this regard, we compared the solid bitumens within both reservoir pores and inclusions in deep carbonate reservoirs of lower Cambrian Longwangmiao Formation (Є1l) and the fourth member of the Sinian Dengying Formation (Z2dn4) in the Moxi area in the central Sichuan Basin. And by analyses of the Raman spectroscopy and bitumen reflectance, our results show a significant difference of maturities for these homologous solid bitumens after experienced the same highest geological temperature. Specifically, based on petrological observations, three types of solid bitumen occurrences (Bit. A, Bit. B, and Bit. C) were identified. Bit. A fills the early fine-grained dolomite dissolution pores with small and dispersed morphology, which eRo-Raman (equivalent vitrinite reflectance obtained by Raman) values show a narrow range from 2.60% to 2.80%. Bit. B with larger, blocky morphology, distributes within pores between the early recrystallized dolomites or the subsequent euhedral dolomites, including the bitumen filling in the fracture as stylolite. Their eRo-Raman values mainly concentrate in the range of 1.80%–1.90%. Bit. C refers to the bitumen inclusions hosted in various diagenetic minerals, with eRo-Raman values range from 2.70% to 2.87%. Since these solid bitumens originated from the same source rocks and have experienced the same highest geological temperature, their heterogeneous eRo-Raman values, therefore, suggest that whether the system open or not matters the thermal evolution of solid bitumen. Our results suggest that caution should be applied when using maturity to study the thermal evolution history in an open system, and hydrocarbons trapped in a closed system (e.g., fluid inclusion) can serve as a more credible recorder of thermal evolution.