Shale Gas Migration Research Articles

Main controlling factors of shale gas migration in the Longmaxi Formation, Changning area of the Sichuan Basin, China

Shale gas migration is a critical geological process in the enrichment of shale gas deposits. Computational fluid dynamics (CFD) methods were employed to investigate this migration process. Utilizing CFD principles, an abstract physical model incorporating stratum dip angles and physical properties was developed. The control variable method was utilized to ascertain the impact of these factors on gas migration. By employing a typical shale gas reservoir profile from the Changning area as the case study, mathematical equations were formulated to describe the evolution of ancient pressures and gas contents under real geological conditions. These equations served as initial conditions for simulating the macroscopic dynamic evolution of the shale gas reservoir through fluid dynamics techniques. The findings indicate that the stratum dip angle dictates the normal stress on bedding planes and the gas pressure gradient along these planes. A larger dip angle corresponds to lesser compaction on the stratum surface, resulting in a steeper pressure gradient and improved gas migration efficiency. Gas predominantly migrates through channels with superior physical properties, and the larger the disparity between these channels and the surrounding rock, the more pronounced the influence on hydrocarbon migration. In the Changning anticline, shale gas migration is predominantly governed by strata uplift, which reduces vertical diffusion and encourages lateral migration from lower to higher regions within the reservoir. In Tiangongtang, on the other hand, early-phase normal fault activity during the last tectonic stage led to significant seepage losses. Although subsequent reverse faulting mitigated these losses, the overall gas content in the reservoir remains relatively low.

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.

Factors Controlling Differences in Morphology and Fractal Characteristics of Organic Pores of Longmaxi Shale in Southern Sichuan Basin, China

Shale gas is a prospective cleaner energy resource and the exploration and development of shale gas has made breakthroughs in many countries. Structure deformation is one of the main controlling factors of shale gas accumulation and enrichment in complex tectonic areas in southern China. In order to estimate the shale gas capacity of structurally deformed shale reservoirs, it is necessary to understand the systematic evolution of organic pores in the process of structural deformation. In particular, as the main storage space of high-over-mature marine shale reservoirs, the organic matter pore system directly affects the occurrence and migration of shale gas; however, there is a lack of systematic research on the fractal characteristics and deformation mechanism of organic pores under the background of different tectonic stresses. Therefore, to clarify the above issues, modular automated processing system (MAPS) scanning, low-pressure gas adsorption, quantitative evaluation of minerals by scanning (QEMSCAN), and focused ion beam scanning electron microscopy (FIB-SEM) were performed and interpreted with fractal and morphology analyses to investigate the deformation mechanisms and structure of organic pores from different tectonic units in Silurian Longmaxi shale. Results showed that in stress concentration areas such as around veins or high-angle fractures, the organic pore length-width ratio and the fractal dimension are higher, indicating that the pore is more obviously modified by stress. Under different tectonic backgrounds, the shale reservoir in Weiyuan suffered severe denudation and stronger tectonic compression during burial, which means that the organic pores are dominated by long strip pores and slit-shaped pores with high fractal dimension, while the pressure coefficient in Luzhou is high and the structural compression is weak, resulting in suborbicular pores and ink bottle pores with low fractal dimension. The porosity and permeability of different forms of organic pores are also obviously different; the connectivity of honeycomb pores with the smallest fractal dimension is the worst, that of suborbicular organic pores is medium, and that of long strip organic pores with the highest fractal dimension is the best. This study provides more mechanism discussion and case analysis for the microscopic heterogeneity of organic pores in shale reservoirs and also provides a new analysis perspective for the mechanism of shale gas productivity differences in different stress–strain environments.

Depressurization-induced production of shale gas in organic-inorganic shale nanopores: A kinetic Monte Carlo simulation

Methane gas production from unconventional reservoirs, such as shale formations, is in high demand due to the global energy needs. However, maximizing production remains challenging due to the ultra-tight porosity, heterogeneity, and complex nature of shale rocks under high pressure. To address this issue, we employ a novel kinetic Monte Carlo (kMC) simulation to investigate the molecular-level behavior of shale gas in both homogeneous and heterogeneous organic-inorganic shale nanopores. This approach not only provides accurate computations of shale gas under high pressure but also aims to uncover the mechanisms of shale gas storage at reservoir pressure and production during pressure drawdown. Our findings indicate that organic shale ultramicropores (pore width < 0.7 nm) contribute significantly to the highest storage capacity of shale gas but pose challenges for production capacity solely through depressurization. In contrast, the free gas zone is the primary source of shale gas production from mesoporous shales, which has a high recovery efficiency but a low production capacity due to less pronounced interaction effects from the shale surface. The heterogeneous nature of shale surfaces leads to asymmetric distributions of density and potential energy across pore widths, with methane molecules favoring locations near organic pore walls due to stronger attractive interactions, while inorganic pore walls facilitate shale gas migration. Interestingly, the optimal ultramicropore size yields the highest recovery efficiency of shale gas via depressurization, characterized by a transition from near-commensurate to incommensurate molecular packing between reservoir and post-drawdown pressures. Based on these detailed molecular simulations, further research is necessary to develop innovative techniques for enhancing shale gas recovery, especially in micropores.

On the transport behavior of shale gas in nanochannels with fractal roughness

As an efficient and environmentally friendly source of energy, shale gas is abundantly available and continues to contribute to the economy growth because of its huge potential for production. However, accurately predicting the transport behavior of shale gas is still challenging due to the small scale and complexity of nanochannels, which impedes the efficiency of recovery. In this paper, the transport behavior of shale gas in nanochannels with fractal roughness is studied by molecular dynamics simulation and theoretical analysis. It is found that the present work functions well to predict the transport behavior of shale gas in nanochannels with roughness. The introduction of fractal roughness hinders the transport of shale gas and leads to a complex trajectory of methane molecules in nanochannels. Furthermore, it is interesting to find the average gas viscosity increases, while the gas flux decreases with the increase in the inclined angle due to the impediment effect after the deflection. These results are helpful for understanding the migration of shale gas in nanochannels with roughness and guiding the improvement of shale gas recovery in practical applications.

Enlightenment of calcite veins in deep Ordovician Wufeng–Silurian Longmaxi shales fractures to migration and enrichment of shale gas in southern Sichuan Basin, SW China

The relationship between fracture calcite veins and shale gas enrichment in the deep Ordovician Wufeng Formation–Silurian Longmaxi Formation (Wufeng–Longmaxi) shales in southern Sichuan Basin was investigated through core and thin section observations, cathodoluminescence analysis, isotopic geochemistry analysis, fluid inclusion testing, and basin simulation. Tectonic fracture calcite veins mainly in the undulating part of the structure and non-tectonic fracture calcite veins are mainly formed in the gentle part of the structure. The latter, mainly induced by hydrocarbon generation, occurred at the stage of peak oil and gas generation, while the former turned up with the formation of Luzhou paleouplift during the Indosinian. Under the influence of hydrocarbon generation pressurization process, fractures were opened and closed frequently, and oil and gas episodic activities are recorded by veins. The formation pressure coefficient at the maximum paleodepth exceeds 2.0. The formation uplift stage after the Late Yanshanian is the key period for shale gas migration. Shale gas migrates along the bedding to the high part of the structure. The greater the structural fluctuation is, the more intense the shale gas migration activity is, and the loss is more. The gentler the formation is, the weaker the shale gas migration activity is, and the loss is less. The shale gas enrichment in the core of gentle anticlines and gentle synclines is relatively higher.

Pore connectivity and microfracture characteristics of Longmaxi shale in the Fuling gas field: Insights from mercury intrusion capillary pressure analysis

Assessing the connectivity of pores and the characteristics of microfractures is essential for comprehending gas migration mechanisms and effectively implementing development strategies in deep shale gas plays. The Fuling gas field, a prominent shale gas reservoir in China, holds promise for deep shale development. This requires a better understanding of variations in pore connectivity among shale samples from different depths of the Fuling gas field. To achieve this goal, this study employs innovative methodologies based on mercury intrusion capillary pressure (MICP), a recognized technique for evaluating material pore structures. In this research, we conducted MICP tests on shale samples of varying sizes to examine variations in pore structure and quantify inaccessible pores. Additionally, repeated MICP tests were performed on the same sample to investigate the spatial distribution of residual mercury and distinguish different pore types associated with flow conduits and storage spaces. Furthermore, a directional MICP experiment was carried out to quantitatively characterize the degree of pore development and anisotropy of microfractures by considering the direction of mercury intruding the sample (parallel or perpendicular to lamination). Our findings revealed that deep shale samples exhibited a higher proportion of inaccessible pores compared to mid-deep ones. Regarding accessible pores, a greater proportion of connected pores was observed in the deep shale samples, while the mid-deep shale samples exhibited a lower proportion. The results from the directional MICP experiment indicated that samples with anisotropy in mercury intrusion volume possessed finer and denser microfractures. However, no evidence was found to correlate the ratio of dead-end and connected pores with sample anisotropy. Overall, this study presents a novel approach for experimentally evaluating pore connectivity and microfracture characteristics in shale reservoirs using MICP. The outcomes contribute to enhancing our understanding of shale gas migration mechanisms, particularly in deep ultra-low-permeability reservoirs, and hold significant implications for future developments in the field.

New insights into the evaluation criteria for high-quality deep marine shale gas reservoirs in the Longmaxi formation: Evidence from organic matter pore development characteristics

Porosity, total organic carbon content, brittle mineral content, and gas content are now the primary references for classifying and evaluating marine shale gas reservoirs in China. Is there a more effective and appropriate reservoir classification scheme for deep marine shale? The Longmaxi Formation in Luzhou, southern Sichuan Basin, China, is the main object of study. Quantitative analysis and modeling using data from field emission scanning electron microscopy, nitrogen adsorption, and logging were used to characterize organic matter (OM) pore multi-scale development and reveal the relationship between OM pore and the high-quality reservoirs. Microscopic and macroscopic indications from OM pores show that a large number of OM pores were developed in high-quality reservoirs. OM surface porosity occupancy of the high-quality reservoir in the Luzhou area was more than 60%. OM porosity occupancy was more than 50%. The nitrogen adsorption–desorption hysteresis loops demonstrate the development of bottleneck and wedge-shaped OM pores. Characterization of multi-scale pore structure by box dimension, pore volume and specific surface area. It is found that the key to the formation of high-quality reservoirs was the massive development of OM mesopores in siliceous shale and the relatively homogeneity structure, which was conducive to the enrichment and migration of shale gas. Furthermore, the improved model decreased the relative error in predicting the OM porosity by about 32.5%. The use of OM porosity occupancy for high-quality reservoir classification was better, and the results were consistent with geological understanding. OM porosity occupancy showed that the area from Lunanxi to Luzhou to Rongchang to Jiangjin was the key exploration area for high-quality reservoirs in southern Sichuan. This study is expected to provide a new idea for OM pore modeling analysis and deep marine shale gas reservoir classification.

Effects of different types of fractures on shale gas preservation in Lower Cambrian shale of northern Sichuan Basin: Evidence from macro-fracture characteristics and microchemical analysis

The Lower Cambrian Qiongzhusi shale is the main producing layer of shale gas in the northern Sichuan Basin. Natural fractures are considered an important factor that influences the exploration and development of shale gas. In this study, outcrops, drill cores, thin sections, fluid inclusions and rare earth element (REE) were analyzed to determine the characteristics, changes in fluid chemistry, and fluid source of different types of fractures and then reveal their effects on the accumulation and preservation of shale gas. Natural fractures of Qiongzhusi shale are mainly composed of non-strata-bounded fractures (NSBFs), strata-bounded fractures (SBFs), and bed-parallel fractures (BPFs). NSBFs span multiple layers, which can significantly enhance the vertical connectivity of shale reservoirs. There are three dominant orientations of NSBFs, as N-S, NNE-SSW, and E-W trends. The E-W trending fractures, which intersect with the maximum principal stress (NWW-SEE) at a small angle, have larger permeability and control the vertical leakage of shale gas. SBFs are confined to individual layers. Homogenization temperatures of aqueous inclusions in SBF veins vary from 149.7 to 172.3 °C. Calcite veins exhibit positive Eu anomalies (δEu = 11.71, 27.9). Analysis of fluid inclusions and rare earth elements indicated that SBF vein-precipitating fluids were derived from the surrounding wall rock. The development of SBFs contributes to shale gas enrichment. BPFs are parallel to bedding planes or intersect at a low angle (<20°). Microstructural analysis suggests that cemented BPFs form from the multiple crack-seal processes. The temperature of fluid during mineral precipitation exceeds 200 °C. REE concentrations vary significantly across the BPF veins (δEu = 2.31–119.37), donating that fluid characteristics episodically changed during vein growth. The methane inclusions trapped in cements and mixing externally sourced fluids indicate that BPFs are the preferential fluid-flow pathway of shale gas and controls the lateral migration of shale gas.

Geological Characteristics of Lower Paleozoic Shale Gas Accumulation in the Yuxi Region, Southern Sichuan Basin: In View of High-Density Methane Inclusions.

Twelve shale fracture veins and forty-nine fluid inclusion assemblages within the veins of 3800–4200 m in three wells located in different tectonic zones in the Yuxi Region, southern Sichuan Basin were selected in this study. The burial and thermal histories of single wells were reconstructed, and time–temperature–pressure of oil and gas filling were clarified using microscopy observation, Raman microprobe analyses, geochemical tests, and fluid inclusion microtemperature measurement. The shale fracture veins of the Wufeng-Longmaxi Formation in the Yuxi Region are mainly formed vertically and horizontally, where the vein-forming fluids are derived from endogenous fluids. A large number of methane inclusions, bituminous inclusions, and methane-bearing bituminous inclusions within the veins confirm the process of oil cracking gas and kerogen cracking gas. The homogeneous temperature (Th) of the aqueous inclusions contemporaneous with the bituminous inclusions ranges from 109.3 to 174.1 °C, which were trapped during 220 to 250 Ma. The homogeneous temperature of the aqueous inclusions contemporaneous with the methane inclusions ranges from 137.3 to 226.8 °C, which were trapped during 160 to 195 Ma and 51 to 56 Ma. The trapped pressure calculated by high-density methane inclusions (0.246–0.293 g/cm3) is between 82.9 and 140.1 MPa, with a pressure coefficient between 1.64 and 2.07. The formation pressure coefficient is nearly two, indicating that the current overpressure is inherited from the overpressure at the maximum burial depth. The earlier the fracture vein opening, the less the damage to the shale gas accumulation, and the more opening-closing phases, the lower the homogeneous temperature of the gas–liquid two-phase aqueous inclusions coeval with the high-density methane inclusions and the greater the degree of damage to the shale gas accumulation. The results provide a basis for further study on the genesis of overpressure and the migration of shale gas.

The effect of water vapor on methane adsorption in the nanopores of shale

Water plays an essential role in shale gas migration and adsorption, and most studies on the influence of water on shale gas adsorption refer only to moisture-equilibrated shales. To investigate the impact of water vapor on methane adsorption in shales, three experiments were conducted and compared: (1) pure methane adsorption onto dry shale (PMD), (2) pure methane adsorption onto moisture-equilibrated shale (PMMS), and (3) simultaneous adsorption of water vapor and methane (SAWM) onto shale. The experimental results reveal that the detrimental impact of water vapor on methane adsorption is inferior to that of preadsorbed water. Two mechanisms, water blocking and adsorption competition, are responsible for the reduction and difference in the methane adsorption capacity and adsorption rate between PMMS and SAWM. Compared to PMD, the methane adsorption capacity decreases by 81–96% in PMMS and by 20–49% in SAWM. Methane adsorption equilibrium is achieved the fastest in PMD. Before the equilibration degree reaches 95%, methane adsorption during SAWM progresses more rapidly, while the reverse occurs when the equilibration degree exceeds 95%. Water vapor can impact micropores more easily during the premoistening process, which obviously lowers methane adsorption. The adverse effect of water vapor on micro-to mesopores is inhibited by high methane partial pressure in SAWM. In PMMS, adsorbed water mainly occupies micropores (0.3–1.5 nm), and methane is adsorbed in pores larger than 1.5 nm. In SAWM, methane preferentially occupies micropores; the competition between methane and water vapor is mainly concentrated in mesopores (1.5–20 nm).

Structural deformation and its pore-fracture system response of the Wufeng-Longmaxi shale in the Northeast Chongqing area, using FE-SEM, gas adsorption, and SAXS

Tectonism caused strong deformation of the Wufeng-Longmaxi Formation in the periphery of the Sichuan Basin, which affected the pore-fracture of the organic-rich shale and migration of shale gas. Samples of structurally deformed shale from the anticline and detachment structure and undeformed shale were collected in the Northeast Chongqing area, China. The investigations of shale structural deformation and its pore-fracture system were performed using optical microscopy, field emission scanning electron microscopy (FE-SEM), low-pressure gas adsorption (LP-GA), and small-angle X-ray scattering (SAXS). The research shows that deformed samples with curved beddings and friction mirrors on the macro level, as well as the microscopically curved organic matter (OM) bands and OM folds, indicate the significant structural transformation and predominantly ductile deformation. The micro-fractures in deformed samples are more developed with different combinations in the two geological structures, showing brittle deformation. Compared with undeformed samples, the number of OM pores in deformed samples is reduced significantly, while the interparticle (interP) pores, intraparticle (intraP) pores, and micro-channels are more developed. The connected pore size distribution (PSD) of all samples is mainly from 0.3 nm to 10 nm. The pore volume (PV) of micropore in the deformed samples is between 0.100 and 0.500 cm3/100 g, and the specific surface area (SSA) is in the range of 2.175–13.554 m2/g. Undeformed samples have a larger PV and SSA than the deformed samples. TOC and the structural deformation control the structure of connected pore, and their PV and SSA are positively correlated with TOC content. Fractal dimension reveals that the surface of connected and closed pore (pore size 3.81–95.34 nm) becomes more complex, and the distribution of small pore (pore size 1.25–3.81 nm) becomes more uniform under the structural deformation of the shale. As the degree of shale deformation increases, the mesopore and macropore volume of connected pores decrease significantly, while the strongly structural deformation of samples results in a substantial increase in micropore volume and SSA. Besides, the PV of both closed and connected pores tends to decrease and the average pore size increases linearly. Furthermore, the shale deformation result in a weakening of the methane adsorption capacity. Shale gas can migrate through the fracture network to the central zone of the detachment structure or the core of the anticline, which has a significant effect on shale gas enrichment and preservation.

Impact of Brittle Deformation on Pore Structure Evolution in Shale: Samples Collected from Different Fault Positions

Tectonic deformation has an important influence on the pore structure and physical properties of shale, and different parts of the same structural style also have great differences. In this study, eight shale samples were collected from two different faults based on the distance from each fault. Comparative analysis of the micro/nanopore structural characteristics and physical properties of these samples was carried out by scanning electron microscopy, liquid nitrogen adsorption, and carbon dioxide adsorption. The results show that as brittle deformation is enhanced (from far away from the fault to inside the fault), the number of organic pores decreases overall, and the connectivity of microfractures and different pore types increases. The total pore volume and total pore specific surface area of shale both increase, the pore volume of mesopores decreases by 31%, and the macropores increase rapidly by 29%. The storage capacity of shale-related folds is higher than that of shale in faults, which is more conducive to the adsorption of shale gas. The permeability of shale in faults is higher than that of shale-related folds, which is more conducive to the seepage and migration of shale gas. The organic layer structure, which is a unique and very rare microstructure at the shale fault site (under shear), was observed inside the fault. It is believed that the organic matter in the shale at the fault site has transformed from the amorphous state at the initial stage of formation to the orientation of the aromatic lamellae to stretching and extension to an increase in the pore size and the enhancement of connectivity. In addition, inorganic nanoparticles were also observed at the fault site. Both structures are important for the small pores in the fault and the increase in reservoir space. When the fault forms a closed environment or tectonic activity ceases in the later period, the early fault location likely becomes a potential high-quality hydrocarbon generation reservoir. These results help improve the understanding of the physical properties of shale reservoirs and shale gas reservoir migration within fault structures and are of great significance for shale gas exploration, development, and prediction.

Study on the Formation Mechanism of Shale Roof, Floor Sealing, and Shale Self-Sealing: A Case of Member I of the Upper Ordovician Wufeng Formation–Lower Silurian Longmaxi Formation in the Yangtze Region

Similar to North America, China has abundant shale resources. Significant progress has been made in the exploration and exploitation of shale gas in China since 2009. As the geological theory of unconventional oil and gas was proposed, scientists have started researching conditions for shale gas preservation. The shale roof and floor sealing and the shale self-sealing are the critical objects of such research, which, however, are still in the initial stage. This article studies the formation mechanism of shale roof and floor sealing and shale self-sealing by taking marine shales from Member I of the upper Ordovician Wufeng Formation–lower Longmaxi Formation in the upper Yangtze region as the research object. Analyses were performed on the TOC content, mineral composition, and porosity, as well as the FIB-SEM, FIB-HIM, and gas permeability experiments on the core samples collected from the marine shales mentioned above. The conclusions are as follows: for the sealings of shale roof and floor, the regional cap rocks, roof, and floor provide sealing for shales due to physical property differences. For the self-sealing of shales, the second and third sub-members of Member I of the Wufeng Formation–Longmaxi Formation mainly develop clay mineral pores which are dominated by macropores with poor connectivity, while the first sub-member of Member I of the Wufeng Formation–Longmaxi Formation mainly develops organic-matter pores, which are dominated by micropores and mesopores with good connectivity. Owing to the connectivity difference, the second and third sub-members provide sealing for the first sub-member, while the methane adsorption effect of shales can inhibit large-scale shale gas migration as it decreases the gas permeability; thus, the organic-rich shales from the first sub-member of Member I of the Wufeng Formation–Longmaxi Formation provides sealing for itself.

Fractal Characteristics and Significance of Different Pore Types of the Wufeng-Longmaxi Formation, Southern Sichuan Basin, China, Based on N2 Adsorption and Image Analysis.

Shale gas is an important unconventional natural gas resource, and its reservoirs have pores with strong heterogeneity, which have an important effect on the adsorption and migration of shale gas, but the specific mechanism is still unclear. To further clarify the pore structure characteristics of shale gas reservoirs and the mechanism of their influence on CH4 adsorption capacity, marine shale samples from the Wufeng–Longmaxi formation of wells N1, N3, and N10 in Changning block, southern Sichuan Basin, China, were selected for total organic carbon (TOC), X-ray diffraction (XRD), N2 gas adsorption (N2-GA), CH4 gas adsorption (CH4-GA), and field emission scanning electron microscopy (FE-SEM). The Frenkel–Halsey–Hill (FHH) model and Slit Island Analysis (SIA) were used to calculate the fractal dimension of the pore system and different types of pores, and their relationship and influence on CH4 adsorption capacity were also discussed. The results show that the fractal dimension could reflect the complexity and heterogeneity of pores. According to the FHH model, fractal dimensions of the surface and structure of the pore system (D1 and D2, D1 < D2) were obtained, and the pore structure was more complex than the pore surface. According to SIA, the surface fractal dimensions of four types of reservoir space (DDP, DOP, DIP, and DMF) decrease progressively, and their main body is 2.60–2.80, 2.40–2.65, 2.20–2.40, and 2.05–2.30. Organic pores and intergranular pores are the most abundant, and so D1 is mainly related to DOP and DIP. In high-TOC samples, D1 is close to DOP, while in low-TOC samples, D1 is close to DIP. The complexity of the pore surface, D1, and specific surface area have a positive correlation, and with the increase of pore surface complexity, methane adsorption capacity could be significantly improved. Therefore, D1 may be used as a characterization parameter of CH4 adsorption capacity, which could provide some evidence to further clarify the adsorption mechanism of shale gas.

Influences of controlled microwave field radiation on pore structure, surface chemistry and adsorption capability of gas-bearing shales

Aiming to explore the feasibility of using microwave field radiation to produce shale gas via temperature swing. The heating behaviors and alterations in physicochemical properties and adsorption capability of gas-bearing shales under the controlled microwave field are preliminarily investigated. Results indicate that the shales can significantly absorb microwave energy. The bulk temperature of shales increases with the duration of microwave radiation. The heating behaviors of shales under the controlled microwave field are probably associated with pyrite and marcasite contained in shales, which greatly determine the complex permittivity and thermal conductivity of shales. Next, the microwave radiation decreases the adsorption pores with pore width below 10 nm, and fractal dimensions of pore surface and pore structure of the shales determined from the Neimark model and the FHH model, while increases the amount of meso- and macropores with pore width above 10 nm, MIP total pore volume and porosity of shales. These alterations in pore structure promote desorption and migration of shale gas within reservoirs. Furthermore, the microwave radiation changes the surface chemistry property of shales. The FTIR analysis reveals that the total content of CO and COOH of shales grows after the microwave radiation, whereas the aromaticity decreases. The alterations in both oxygenic functional groups and aromaticity are prone to promote shale gas desorption from shale matrix by weakening the intermolecular force between shale gas and shale matrix. Finally, the microwave radiation decreases the maximum CH4 adsorption capacity of the shales, the decreasing amplitude of which is 12.70–47.83%. In conclusion, the aforementioned heating behaviors and alterations in physicochemical property and adsorption capability of shales under the controlled microwave field imply that microwave radiation is an alternative option to enhance shale gas production.

Effect of Surface Type on the Flow Characteristics in Shale Nanopores

The underlying mechanism of shale gas migration behavior is of great importance to understanding the flow behavior and the prediction of shale gas flux. The slippage of the methane molecules on the surface is generally emphasized in nanopores in most predicted methods currently. In this work, we use molecular dynamic (MD) simulations to study the methane flow behavior in organic (graphene) and inorganic (quartz) nanopores with various pore size. It is observed that the slippage is obvious only on the graphene nanopores and disappeared on the quartz surface. Compared with the traditional Navier-Stokes equation combined with the no-slip boundary, the enhancement of the gas flux is nonnegligible in the graphene nanopores and could be neglected in the quartz nanopores. In addition, the flux contribution ratios of the adsorption layer, Knudsen layer, and the bulk gas are analyzed. In quartz nanopores, the contributions of the adsorption layer and the Knudsen layer are slight when the pore size is larger than 10 nm. It is also noted that even if the Knudsen number is the same, the flow mode may be various with the effect of the pore surface type. Our work should give molecular insights into gas migration mechanisms in organic and inorganic nanopores and provide important reference to the prediction of the gas flow in various types of shale nanopores.

Petrophysical properties difference of organic-rich and organic-poor shale reservoir using low-field nuclear magnetic resonance experiment in the Sangzhi block, South China

The petrophysical properties of rocks have an important influence on shale quality. To characterize the difference of petrophysical properties between organic-rich and organic-poor shale reservoirs, we used the low-field nuclear magnetic resonance (NMR) technique and field emission scanning electron microscopy analysis after argon-ion polishing or natural section to measure porosity and permeability from six core samples from well SY6 in the Sangzhi block, Northwest Hunan province. Some information about pore types, pore structure, residual porosity, movable porosity, and permeability based on the T2 spectrums’ difference of organic-rich and organic-poor shale samples were discussed. The shale sample test results show that the main pores size is mesopore, which provide most of shale gas reservoir space. The continuous peaks demonstrated the pores’ connectivity better than the isolated peaks, and shale gas can migrate freely between these connected pores and fractures. The permeability of all samples calculated by the classic Coates model is extremely low, which is not conducive to the migration of shale gas. We evaluated the dominating factors of NMR porosity and permeability and found that the relationships between NMR porosity and permeability and total organic carbon content, quartz minerals, and clay minerals are not clear, which may be a comprehensive influence. The research results have important guiding significance for shale reservoir quality evaluation in this area.

Pore characteristics of the lower Sinian Doushantuo Shale in the Mid-Yangtze Yichang area of China: Insights into a distinct shale gas reservoir in the Neoproterozoic formation

The Lower Sinian Doushantuo Shale comprises the oldest Neoproterozoic shale gas reservoir in the Middle Yangtze Yichang area of China, which makes the study of their pore characteristics critical to future shale gas exploration and exploitation. Geochemical, petrographical, and pore characteristics are studied in detail, with focused ion beam scanning electron microscopy (FIB-SEM) image analysis to further support and confirm the interpretations of the nano-scale pore structure characteristics. High total organic carbon (TOC) content, high thermal maturity, and considerable brittle mineral content indicate promising potential of the Doushantuo shale. High TOC samples suggest elevated micro-meso porosity, and H2(b) and H3 type hysteresis loops indicate inkbottle, slit-like, and flake-like pore types. Significant inorganic pores are commonly observed in dolomite, pyrite, and apatite, which are characterized by diamond or irregular shapes, with pore diameters ranging from 5 nm to 1000 nm as a result of the interaction between the minerals and the acidic organic fluids. Clustering organic matter (OM) pores are observed with pore diameters ranging from 5 nm to 50 nm; they are characterized by sponge-like, elliptical, and alveolate shapes, which indicate minor organic matter (OM) pores. More substantial organic matter (OM) pores can also be found around or between the pyrite and apatite. Fractures can be clearly observed between the organic matter and minerals with lengths of approximately 10 μm and 50 nm in width, which serve as conduits for shale gas migration. The pores in the Doushantuo Shale are dominated by inorganic pores and minor organic matter (OM) pores, which are different from the pore structure of the Wufeng-Longmaxi Shales in the Sichuan Basin. The Doushantuo Shale organic matter (OM) pores are much smaller and more densely distributed than those in the Wufeng-Longmaxi Shales. The different organic matter origins of these two shales have caused distinct organic matter (OM) pore-development mechanisms. Organic matter (OM) pores and inorganic pores could contribute to the volume of the adsorbed gas and free gas, respectively, which provide significant reservoir space in the Lower Sinian Doushantuo Shale in the Yichang area.

A Cause Analysis of the High-Content Nitrogen and Low-Content Hydrocarbon in Shale Gas: A Case Study of the Early Cambrian in Xiuwu Basin, Yangtze Region

There are successes and failures in the exploration of marine shale gas in South China. In some shale gas plays with great basis for hydrocarbon generation, a phenomenon exists that gas loggings reflect low gas bearing in some of the wells and the gas is dominated by nitrogen rather than hydrocarbon gas. The study of nitrogen concentration in shale gas contributes to solve the question that how shale gas diffuses in complex tectonic areas, which helps to figure out the preservation requirements and accumulation mechanisms of shale gas and avoid exploration crisis. This study focused on the lower Cambrian shale in Xiuwu Basin, Lower Yangtze Region, with emphasis on the well Jiangye-1, using gas component analysis, stable nitrogen isotope analysis, overburden permeability tests in parallel and perpendicular directions, and FIB-HIM experiments, also combining with core description, outcrop observation, and seismic interpretation to explore the causes of the high-content nitrogen and low-content hydrocarbon in the lower Cambrian shale gas. The results show that the nitrogen of the lower Cambrian shale in Xiuwu Basin is derived from the atmosphere and the deep crust-upper mantle. The bedding planes and the detachment layer at the bottom of the lower Cambrian compose the lateral pathways, and the widespread deep faults are the vertical pathways for shale gas migration and diffusion. Combining these two, an effective pathway network was built, favorable to gas exchange between the shale gas interval and the atmosphere, partly leading to the concentration of nitrogen and the diffusion of hydrocarbon gas. In the Jurassic, the magmatic activities occurred frequently in the surrounding areas, which not only brought nitrogen from the deep crust-upper mantle but also increased the value of paleo-heat flow even though the basin began to uplift, which promoted the graphitization of organic matter and the collapse of organic pores and accelerated the loss of shale gas. Based on the study above, an explanation model was summarized to expound the causes of high-content nitrogen and low-content hydrocarbon in shale gas plays near the plate-active region in Xiuwu Basin, Lower Yangtze Region.