• Energy Research

Abstract Shale gas reservoir performance and canister desorption experiments of the Lower Cambrian organic-rich shales in the eastern Upper Yangtze Platform reveal a significant difference in shale gas content between the Dabashan arc-like fold-thrust belt in northeastern Chongqing (Deformed Zone) and the slightly folded area in southeastern Chong (Non-deformed Zone). Integrated pore characterization methods including scanning electron microscopy (SEM), low-temperature N2 and CO2 adsorption, and mercury injection capillary pressure (MICP) analyses were comparatively conducted in both areas in order to examine shale gas reservoir pore size variations and thus the possible microscopic pore structure controls on shale gas enrichment. The Lower Cambrian shales in both Deformed Zone (DZ) and Non-deformed Zone (NDZ) were deposited in the deep-water shelf and show similar organic matter richness and thermal maturity. The majority of organic matter (OM)-hosted pores in DZ samples are in nanoscale size range with the dominance of micro-fractures within the OM or at the interface of OM and minerals. In contrast, OM-hosted meso-(2–50 nm) to macropores (>50 nm) are the dominant pore types in the NDZ samples. OM-hosted micropores ( The Dabashan arc-like fold-thrust belt took place by the end of the Late Triassic, while the Lower Cambrian shales have reached thermal maturity peak. OM-hosted meso-(2–50 nm) to macropores (>50 nm) in DZ samples are most probably collapsed during structural deformation related to tectonic compression, while micropores due to their smaller size survived the tectonic stress. The OM-hosted micropores are the main storage space for adsorbed gas in the DZ area. The dominance of micro-pores in DZ and lack of connection between those pores and matrix pores led to higher gas content in DZ samples. On the contrary, the well-connected OM-hosted pore network in NDZ allows easier gas flow in the rock matrix that eventually led to significant gas leakage during uplift and exhumation and lower gas content in this zone. The results of this study suggest that structural deformation can potentially change the pore structure of shales and thus shale gas content which has major significance for shale gas exploration and development in south China where had experienced complex tectonic movements.

The question of how to mine safely in close multi coal seams is the main concern for coal operators, in particular for large-dip coal seams with complex geological and mechanical conditions. This paper presents a detailed similarity simulation on the movement characteristics of the overburden and the stress distribution of underlying strata in terms of a specific coal mine in the Tielieke mining area of the Kubai coalfield via a three-dimensional photogrammetry system and a high-speed static resistance analyzer. The results show that the overburden strata are asymmetrically deformed around the coal pillar and the fracture area is perpendicular to the longwall with an “M” shape when deeper coal is mined. Moreover, the asymmetric movement of overburden results in the non-uniform distribution of stress on the floor of the coal pillar and ribs. In particular, stress is closely related to the location of the longwall, and stress of the coal pillar is much larger when it is closer to the deep side. The floor stress relief degree of the longwall in the deep zone is higher than that of its counterparts, providing a theoretical foundation for a reasonable layout and a support technique for roadways. The main contribution of this research that it can be used as a reference in maintaining the integrity of surrounding rock for large-dip coal seams with close distances.

The main factors controlling the enrichment and high yield of shale gas were analyzed based on the recent research progress of depositional model and reservoir characterization of organic-rich shale in China. The study determines the space-time comparison basis of graptolite sequence in the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation and proposes the important depositional pattern of marine organic-rich shale: stable ocean basin with low subsidence rate, high sea level, semi-enclosed water body, and low sedimentation rate. Deposited in the stage of Late Ordovician-Early Silurian, the superior shale with thickness of 20−80 m and total organic carbon (TOC) content of 2.0%−8.4% was developed in large deep-water shelf environment which is favorable for black shale development. Based on the comparison among the Jiaoshiba, Changning and Weiyuan shale gas fields, it is believed that reservoirs of scale are mainly controlled by shale rich in biogenic silica and calcium, moderate thermal maturity, high matrix porosity, and abundant fracture. The shales in the Wufeng and Longmaxi formations are characterized by porosity of 3.0%−8.4%, permeability of 0.000 2×10−3−0.500 0×10−3 μm2, stable areal distribution of matrix pore volume and their constituents, great variation in fracture and pore characteristics among different tectonic regions as well as different well fields and different intervals in the same tectonic. The Cambrian Qiongzhusi shale features poor physical properties with the porosity of 1.5%−2.9% and the permeability of 0.001×10−3−0.010×10−3 μm2, resulted from the carbonization of organic matter, high crystallinity of clay minerals and later filling in bioclastic intragranular pores. Four factors controlling the accumulation and high production of shale gas were confirmed: depositional environment, thermal evolution, pore and fracture development, and tectonic preservation condition; two special features were found: high thermal maturity (Ro of 2.0%−3.5%) and overpressure of reservoir (pressure coefficient of 1.3−2.1); and two enrichment modes were summarized: “structural sweet spots” and “continuous sweet area”. Key words: shale gas, organic-rich shale, sedimentary model, reservoir characterization, sweet spot area, Jiaoshiba shale gas field, Changning shale gas field, Weiyuan shale gas field

Abstract The Lower Silurian Longmaxi Formation is an organic-rich (black) mudrock that is widely considered to be a potential shale gas reservoir in the southern Sichuan Basin (the Yangtze plate) in Southwest China. A case study is presented to characterise the shale gas reservoir using a workflow to evaluate its characteristics. A typical characterisation of a gas shale reservoir was determined using basset sample analysis (geochemical, petrographical, mineralogical, and petrophysical) through a series of tests. The results show that the Lower Silurian Longmaxi Formation shale reservoir is characterised by organic geochemistry and mineralogical, petrophysical and gas adsorption. Analysis of the data demonstrates that the reservoir properties of the rock in this region are rich and that the bottom group of the Longmaxi Formation has the greatest potential for gas production due to higher thermal maturity, total organic carbon (TOC) enrichment, better porosity and improved fracture potential. These results will provide a basis for further evaluation of the hydrocarbon potential of the Longmaxi Formation shale in the Sichuan Basin and for identifying areas with exploration potential.

Previous studies have shown that shale oil mobility depends on the relative content of free oil and adsorbed oil. However, the research on how to establish a shale oil mobility evaluation is relatively insufficient. This study aims to use pyrolysis data before and after extraction to accurately identify the content of free oil and adsorbed oil, analyze the influencing factors of shale oil mobility, characterize the hydrocarbon generation and expulsion process, and evaluate shale oil mobility. We utilized an integrated mineralogical and geochemical dataset from the PS18-1 well in the Liutun Sag, Dongpu Depression, Bohai Bay Basin. The results show that the adsorption capacity of type I organic matter (OM) on shale oil is greater than that of type II OM, the OM abundance is of great significance to shale oil mobility, and that quartz and feldspar can promote shale oil mobility. The Tmax corresponding to the threshold of hydrocarbon expulsion is 438~440 °C, and the oil saturation index (OSI) is about 158 mg/g TOC. There are four small intervals: a (3257 m~3260 m), b (3262 m~3267 m), c (3273 m~3278 m), and d (3281 m~3282 m) meeting the conditions of hydrocarbon expulsion. Large-scale hydrocarbon expulsion occurred in interval a, a small amount of hydrocarbon expulsion in interval b, a large amount of hydrocarbon expulsion in interval c, and almost no hydrocarbon expulsion in interval d. Based on the crossplot of S1 and TOC, combined with other parameters such as OSI, hydrocarbon generation potential (HGP), and free and adsorbed oil, we established an evaluation chart of shale oil mobility and divided it into five categories: A, B, C, D, and E. While categories A and C have good mobility and great resource potential, categories B and D have relatively poor mobility and medium resource potential, and category E has little mobility and is an invalid resource.

AbstractBoth of the coalbed methane (CBM) and shale gas reservoirs are dominated by nanometer‐scale pores with their nanopore structures controlling the occurrence, enrichment, and accumulation of natural gas. Low‐pressure nitrogen gas adsorption (LP‐N2GA), low‐pressure carbon dioxide gas adsorption (LP‐CO2GA), high‐pressure methane adsorption (HPMA), and field emission scanning electron microscope (FE‐SEM) experiments were conducted on 14 different‐rank coal samples and nine Longmaxi shale samples collected from various basins in China to compare their nanopore characteristics. The FE‐SEM results indicate that the pore structures of both the coal and shale samples consist of nanometer‐sized pores that primarily developed in the organic matter. The types of their isothermal adsorption curves are similar. However, the coal and shale samples possess various hysteresis loops, which suggest that the nanopores in shale are open‐plated, whereas those in coal are semi‐open. Furthermore, the specific surface area (SSA) and pore volume (PV) of the micropores in coal are much larger than those of the mesopores, with the micropore SSAs accounting for 99% of the total SSA in the coal samples. However, the micropore SSAs in the shale samples only account 42.24% of the total SSA. These different nanopore structures reflect their different methane adsorption mechanisms. The methane adsorption of coal is primarily controlled by the micropore SSA, whereas that of shale is primarily controlled by the mesopore SSA. If we use mesopore SSA to analyze its impact on methane adsorption capacity of coal and shale, it will be mismatched. However, no mismatching relationship exists between the total SSAs and adsorption capacities of coal and shale. This study highlights the controlling effect of total SSA on methane adsorption capacity.

To better understand the physical and mechanical behavior of weakly cemented rock with different moisture contents for the success of water-preserved mining, this paper presents the systematic tri-axial compression tests on three typical rock samples (i.e., mudstone, sandstone, and sandy mudstone) sampled from Ili mining area, where the environmental requirements for water conservation are significantly strict. Both the influences of moisture content and confining pressure on the failure mode and the stress-strain behavior of weakly cemented rock have been discussed and compared with each other. Test results showed that: (1) compared to sandstone and sandy mudstone, both the peak stress and residual stress of the weakly cemented mudstone are much more sensitive to confining pressure and moisture content. In detail, the peak stress is very relevant to moisture content, whereas, the residual stress is more sensitive to the confining pressure, (2) with the increase of moisture content, both the yield and ductility of weakly cemented mudstone have been significantly enhanced. However, a similar experimental observation has been found for sandstone and sandy mudstone, and (3) the microstructure and the mineral component are believed to be the two main factors leading to the scatter in terms of the stress-strain behavior for different weakly cemented rocks. Experimental results and discussions presented in this paper can provide the guideline for further research on the application of water-preserved mining in other coal mines with a similar geological condition.

Isothermal adsorption and desorption experiments under different temperatures were carried out with the Longmaxi Formation shale samples collected from southern Sichuan. The experimental results show that temperature affects the adsorption and desorption capacity of shale, the adsorption capacity of shale decreases with temperature increase. The adsorption curve and desorption curve of shale are not coincident and the thermodynamic reason for the hysteresis of the desorption curve is that the isosteric heat of the shale adsorption process is greater than that of the desorption process. The Langmuir model and desorption model can describe the isothermal adsorption and desorption processes very well, respectively. Isothermal adsorption and desorption curves under different temperatures can be predicted by isosteric heat curves which match the experimental results. Shale gas production is a process of gas desorption and the desorption characteristics directly impact the production of shale gas, so the desorption model should be taken into consideration in the shale gas production forecast and numerical simulation. Key words: shale, temperature, adsorption, desorption, isosteric adsorption heat