International Journal of Coal Geology最新文献

Methane oxidation affects hydrocarbon accumulation and carbon cycling with important geological and paleoclimatic responses. However, the petrological and geochemical evidences that can clearly discern anaerobic (AOM) and thermochemical (TOM) oxidations in petroliferous basins are unclear, causing the disputes if these two processes can take place in specific conditions. Here, the Baikouquan Formation (T₁b) in the Mahu Sag, Junggar Basin, China, was used as the first case study for comprehensive petrological and geochemical analyses to explore this scientific issue. Results indicate that the two main types of T₁b calcite cement record different methane oxidation mechanisms. Calcite cements filling intergranular pores were formed during early diagenesis in relatively shallow-burial stages, through AOM with high-valence Mn oxides as electron acceptors, and with compositions of −47.5 ‰ < δ¹³C < −30.9 ‰, 1.1 wt% < MnO < 5.8 wt%, and 0.02 wt% < FeO < 0.13 wt%. Calcite cements filling intragranular dissolution pores were formed through TOM with high-valence Mn oxides as electron acceptors during mesogenesis during relatively deep-burial stages, with compositions of −39.7 ‰ < δ¹³C < −14.3 ‰, 0.43 wt% < MnO < 11.00 wt%, and 0.03 wt% < FeO < 0.36 wt%. Thus, methane oxidation underwent a transition from AOM to TOM with increasing depth, as recorded by the calcite cements with different occurrences. This transition may be a common feature of clastic strata in petroliferous basins.

The Middle Miocene Balikpapan Formation is exposed in the Samarinda Anticlinorium, which forms part of the Lower Kutai Basin situated on East Kalimantan, Indonesia. The Balikpapan Formation is considered the main source rock for oil and gas fields in Lower Kutai Basin. This study integrates sedimentology, organic geochemistry, organic petrography and calcareous nannofossil analysis to characterize the depositional environment, to determine the source of the organic matter, and to assess the hydrocarbon potential of the Balikpapan Formation. The studied sections contain at one locality calcareous nannofossil assemblages with low diversity including Sphenolithus heteromorphus, suggesting nannofossil zones NN4 – NN5 (upper Burdigalian - Langhian-lower Serravallian) are restricted to the Air Putih section in the northeastern part of the study area. Six facies associations were identified in the study area, comprising eleven lithofacies, interpreted as fluvial-deltaic to shallow marine in origin. The fine-grained lithofacies include shale, coaly shale and coal while the coarse-grained facies include sandstone and sandy conglomerates. The geochemical results (TOC) indicate that the analyzed samples have strongly varying total organic carbon (TOC) contents. The organic matter is composed of type III (gas-prone) and type II-III (mixed oil and gas prone) kerogen, with HI values ranging from 32 to 252 mg HC/g TOC. The Rock-Eval parameter T_max 409–441 °C and vitrinite reflectance values (0.40–0.67 %Rr) indicate that the sediments are immature to marginal mature. The rank of coal in the Balikpapan Formation ranges from the sub-bituminous to the high-volatile bituminous B stage.

The Babouri-Figuil Basin is an intracratonic basin (half-graben) in northern Cameroon that is genetically connected to the Benue Trough from Nigeria, and is an area of interest in terms of petroleum prospectivity. Recent studies highlighted the presence of organic-rich formations in the basin. However, none of these works have identified factors that governed the accumulation of organic matter (OM) in the sediments. The main objective of this work is the characterization of these formations through palynofacies and organic geochemical techniques (total organic carbon - TOC, total sulfur, insoluble residue and biomarkers), in order to determine the organic facies, their depositional environments and the main drivers for organic enrichment in the basin. The current study reveals that black shale and massive claystone lithologies constitute the main organic-rich formations in the basin, with TOC reaching up to 26.08 wt%, being characterized by a dominance of bacterially-derived amorphous OM. Palynofacies and biomarker data revealed that these formations are positively associated with anoxic conditions and a partly highly saline and stratified lake water column. The deposition of organic-rich formations in the Babouri-Figuil Basin was mainly controlled by restriction conditions which developed in connection with the regional tectonic framework. The Lower Cretaceous rifting episode in the West and Central African Rift System (WCARS) basins led to the formation of accommodation space, a reduction in water levels, and the development of anoxic conditions within the basin, facilitating the deposition of organic-rich formations. Therefore, the organic enrichment of the Babouri-Figuil Basin has been predominantly controlled by its tectonic evolution, particularly during the syn-rift phase. This phase created favorable conditions for the deposition and preservation of OM, including the establishment of anoxic conditions. Additionally, the paleoclimate (arid conditions), the development of bacterial biomass, and the basin's paleogeography all played a significant role in this process. The organic-rich formations of the Babouri-Figuil Basin show characteristics of prospective petroleum source rocks (high organic content, high proportion of oil-prone kerogen, significant thickness and lateral extension). The combination of organic-rich formations with sandstone deposits above and extensive claystone/shale deposits on top can indicate the presence of an oil play in the basin. A detailed study with broader sampling is needed to investigate thoroughly the variation of organic facies and the influence of paleoenvironmental factors that control the deposition of thick source rock intervals.

The Orzesze-1 exploratory well with a depth of 3708 m (TVD) was drilled in 2019–2020 in the depocentre of the Upper Silesian Coal Basin (USCB). The methane content in the coal seams has been tested to a depth of 2840 m and the sorption capacity of the coal to a depth of 2576 m. These are the deepest measurements in the USCB so far. The vertical distribution of methane content in the borehole shows two depth zones of interest, the first at a depth 883 m to about 1300 m (maximum methane content about 12 m³/t coal^daf) and another in the range of 1500–2840 m, that is, to the maximum measurement depth, so the actual lower boundary depth of this zone is unknown. The maximum methane content here exceeds 18 m³/t coal^daf at a depth of >2800 m. Both zones are separated by an interval of reduced methane content of about 5 m³/t coal^daf at a depth of approximately 1400 m. The gas composition is dominated by methane (∼90%), and the content of carbon dioxide increases to approximately 15% at a depth of >2300 m. The methane-bearing zone at ∼900–1300 m corresponds to the zone of high- and medium-volatile bituminous coal (second coalification jump), while the highest methane content at a depth of >2800 m was determined in anthracite. The methane sorption capacity of the coal seams oscillates between 16 and 40 m³/t coal^daf with a maximum in anthracite at a depth of >2800 m, where the temperature of the rock approaches 100 °C and the deposit pressure exceeds 28 MPa. The highest sorption capacity in anthracite results from its inner structure characterised by the predominance of ordered aromatic lamellas and the dominance of vitrinite macerals (>70%), which contain coal micropores accumulating adsorbed methane. The comparison of the sorption capacity of the tested coal and the measured methane content displays undersaturation of 11–59%, however, due to significant gas content in the deep zone (depth > 1500 m), the drilling area can be considered as a prospect for further exploration and development of coalbed methane (CBM).

Accurately identifying sweet spots remains a significant challenge for the petroleum industry despite the growing amount of information available for unconventional hydrocarbon resources. These challenges may stem from the inorganic geochemical heterogeneities in source rock composition that can vary within a given basin over time. This study investigates the relationship between source rock composition and the resulting hydrocarbon expulsion, retention, and thermal maturation behavior through artificial maturation experiments on Late Cretaceous (Maastrichtian) Jordanian source rocks (JSR). The JSR is a carbonate-rich Type IIS source rock, which is compositionally similar to major Arabian unconventional prospects (Tuwaiq Mtn, Hanifa, and Shilaif/Natih Fms) as well as other major carbonate source rocks (Eagle Ford & La Luna Fms). However, it is thermally immature and, therefore, can be considered as an immature analog to the mature unconventional Type IIS source rock prospects.

This study utilized a thick JSR interval in the Al-Lajjun area of western Jordan, by using core samples from a 72 m long vertical well. Initial characterization of the source rock interval using bulk organic and inorganic geochemical parameters revealed three distinct geochemical cycles. Representative homogeneous plug samples from each cycle underwent artificial maturation experiments and showed differences in hydrocarbon expulsion and retention trends along with a difference in thermal maturity. Samples with higher silica content exhibited an early hydrocarbon expulsion as compared to Ca-dominated samples. The Ca-rich samples demonstrated a higher hydrocarbon retention and delayed expulsion at corresponding maturity stages as compared to the Si-rich samples. Additionally, the silica-rich samples also displayed lower Tmax values than the calcium-rich samples of similar thermal maturity.

The findings of this study highlight the significance of inorganic compositional heterogeneities within a source rock interval that can lead to the formation of multiple play fairways with varying hydrocarbon expulsion and thermal maturity characteristics. These insights emphasize the need for a more comprehensive understanding of source rock composition when assessing thermal maturity and identifying sweet spots for unconventional hydrocarbon exploration and production.

This research presents a new method for studying gas-water two-phase flow in fractured coal, integrating cutting-edge imaging techniques. We combine dynamic positron emission tomography (PET), high-resolution X-ray micro-computed tomography (micro-CT), and unsteady-state fluid flow experiments. First, micro-CT under reservoir pressure conditions maps the sample's fracture structure at high-resolution. Then, helium injection into a water-saturated sample simulates gas flow in a coal seam during production. Real-time PET monitoring captures the dynamic displacement process within the fractures. This approach yields crucial data on gas injection volume, pressure variations, and water production, enabling relative permeability curve prediction. Finally, multi-scale image analysis merges high-resolution micro-CT with dynamic PET images, overlaying the flow path onto the fracture network. This innovative method leverages the strengths of both PET and micro-CT, offering unprecedented visualization of gas-water flow behaviour in fractured coal. PET images play a crucial role in providing both spatial and temporal water saturation profiles since the activity mapping directly correlates with water volume distribution in the fractures. The consistency between the initial activity profile along the sample from PET and the fracture volume distribution calculated from micro-CT images confirms the reliability of PET data. The workflow proposed in this paper can be used to monitor two phase flow displacement in unconventional rocks such as coal and be applied for determination of relative permeability curves.

The importance of kerogen kinetics extends beyond hydrocarbon generation, encompassing thermal modeling, organic matter heterogeneity, and the assessment of thermal decomposition. Our study focuses on analyzing the organic and inorganic signatures of source rock intervals, by integrating also literature maceral compositions, to identify potential correlations between kinetics and the mineral matrix. To achieve this, nineteen samples from proved Mesozoic source rock intervals in Western Greece were analyzed. Rock-Eval 6 pyrolysis experiments identified thermally immature to slightly mature, mainly type II, and mixed I-II kerogens. X-ray fluorescence and X-ray diffraction analysis revealed a predominance of carbonate over silicate minerals, indicating a carbonate-dominated source rock character and predominantly reducing marine depositional conditions. High sulfur contents, primarily observed in the Late Triassic – Early Jurassic interval, suggest euxinic conditions and the presence of II(S) kerogens. Bulk rock kinetic analysis revealed activation energy distributions mainly ranging from 43 to 60 kcal/mol. The Late Triassic – Early Jurassic and Early – Mid Jurassic intervals show greater heterogeneity with broad distributions, while the Mid – Late Jurassic and Early Cretaceous intervals exhibit more homogeneity, with two to three principal activation energy peaks. Kerogen isolation revealed differences in activation energies and frequency factors between the bulk rock and the kerogen, with the mineral matrix potentially having a minimal effect in the reaction rate. This research offers insights into the bulk kinetics of marine source rocks linked with global oceanic anoxic events, with broader implications to the hydrocarbon exploration in the fold and thrust belt of Western Greece, and to analogue geological settings worldwide.

Radiological and health risks arising from ²²⁶Ra, ²³²Th, and ⁴⁰K in topsoil due to coal combustion in Plomin thermal power plant were assessed: outdoor absorbed dose rate in air (D), annual outdoor effective dose rate (D_ef), external hazard index (H_ex), internal hazard index (H_in), and excess lifetime cancer risk outdoors (ELCR_out). Spatial distribution of risks around the plant was studied and relative contributions of ²²⁶Ra, ²³²Th, and ⁴⁰K to D (applies to D_ef and ELCR_out as well), H_ex, and H_in were determined. The risks were studied at two soil depths (A: 0–10 cm, B: 10–25 cm), radially around the plant at 1 km, 5 km, and 10 km distances from the plant, and in a downwind (SW) profile at 0.1–1 km distance from the plant. Elevated D, D_ef, H_in, and ELCR_out were determined, while H_ex was not elevated. Almost all D, D_ef, and ELCR_out values were above the world average for soils (58 nGy/h, 0.07 mSv/y, and 0.29 × 10⁻³, respectively). D, D_ef, and ELCR_out were: 32–338 nGy/h (mean value: 116 nGy/h), 0.039–0.414 mSv/y (mean value: 0.142 mSv/y), and 0.17 × 10⁻³–1.79 × 10⁻³ (mean value: 0.61 × 10⁻³), respectively. H_ex was in the 0.18–1.98 range (mean value: 0.69), with only two extreme values above the recommended limit of 1. H_in was in the 0.22–3.67 range (mean value: 1.02), with most of the values above the recommended limit of 1 in the downwind profile and at one station with extremes (1 km from the plant). A “hot spot” was determined for all risks at 1 km distance from the plant in the wind direction (SW from the plant). The next highest, elevated, risks were observed in the downwind profile stations. The most important parameters influencing spatial distribution of risks are ²²⁶Ra activities in soil, wind direction, and distance from the plant. ²²⁶Ra is generally the most important contributor to risks in soils, while ⁴⁰K is the least important. ²²⁶Ra and ²³²Th were found to be the most significant and comparable contributors to D, D_ef, H_ex, and ELCR_out. Only ²²⁶Ra was found as the most significant contributor to H_in in the studied area. Elevated risks are partially from the natural source (carbonate bedrock) and partially from the power plant (coal combustion and handling, ash deposition on soil).

The chemical characteristics of coal reservoir water are important for studying the formation and enrichment of biogenic coalbed methane (BCM). Based on geological and sampling test data, this paper studied the geochemical characteristics and formation mechanisms of high-salinity coal reservoir water (CRW) in the Jurassic Yan'an Formation of the Binchang area in the southern Ordos Basin. The results show that the TDS contents of the CRW in the Binchang area are between 7577.38 and 15,138.61 mg/L (av. 13,268.95 mg/L), which is high-salinity brackish water. The ion types of CRW are mainly Na⁺, Cl⁻ and HCO₃⁻, and the correlations between TDS and Na⁺ and Cl⁻ are close to 1. The Piper trilinear diagram indicates that the evolution direction of the CRW is deep concentrated brine, and the hydrochemical type is the NaCl type. The ¹²⁷I concentrations of CRW are between 285 and 484 μg/L, which are much higher than the values of 55.88 μg/L for seawater. The results of ¹²⁹I dating show that the minimum age of the CRW in the study area is between 6.7 Ma and 39.97 Ma, which is much younger than the actual geological age of the Yan'an Formation. The hydrogen and oxygen isotope results show that the CRW in the study area experiences an apparent oxygen drift, indicating that the coal reservoir of the Yan'an Formation has good sealing and a long retention time for the CRW. The hydrodynamic factors show that the hydrodynamic conditions of the coal reservoir are weak, and the primary ions in the CRW originated from the dissolution of salt rocks. The main ion differentiation indices show that high-salinity coal seam water is mainly formed by evaporation, and the ion exchange between CRW and the surrounding rock and the alternating adsorption of cations in water are very weak. Evaporation and diagenesis lead to an increase in the contents of Na⁺, Cl⁻ and I⁺ in coalbed water, which in turn leads to an increase in the total dissolved solids contents of CRW and its evolution toward concentrated brine. The genesis and evolution of the CRW in the study area are affected by the combination of the relationships among the paleoclimate, aquifers and aquifuges, and tectonic evolution processes. The CRW in the study area has experienced five evolution stages, i.e., sedimentary water and diagenetic water, high-salinity infiltration water, primary mixed water, paleoatmospheric precipitation recharge water, and secondary mixed water. The above understanding can provide a basis for studying the formation period and accumulation mechanism of BCM and provide a hydrogeological basis for water resource utilisation and pollution prevention and the control of high-salinity water.