Shale Adsorption Research Articles

Multifractal Analysis of the Structure of Organic and Inorganic Shale Pores Using Nuclear Magnetic Resonance (NMR) Measurement

The multifractal structure of shale pores significantly affects the occurrence of fluids and the permeability of shale reservoirs. However, there are few studies on the multifractal characteristics of shale pores that distinguish between organic and inorganic pores. In this study, we obtained the pore size distribution (PSD) of organic and inorganic shale pores separately by using a new NMR-based method and conducted a multifractal analysis of the structure of organic and inorganic shale pores based on PSD. We then investigated the geological significance of the multifractal characteristics of organic and inorganic shale pores using two multifractal characteristic parameters. The results showed that the structures of both organic and inorganic pores have multifractal characteristics. Inorganic pores have stronger heterogeneity and poorer connectivity compared to organic pores. The multifractal characteristics of inorganic pores significantly affect shale permeability and irreducible water saturation. Greater heterogeneity in the inorganic pore structure results in lower shale permeability and higher irreducible water saturation. Meanwhile, better connectivity leads to higher shale permeability and lower irreducible water saturation. The multifractal characteristics of organic pores significantly affect the shale adsorption capacity and have a weak impact on irreducible water saturation. Greater heterogeneity in the organic pore structure results in the shale having stronger adsorption capacity and higher irreducible water saturation The results also indicate that the multifractal characteristic parameters of inorganic pores can be regarded as an index for estimating the irreducible water saturation and flowback rate of fracturing fluid, and the multifractal characteristic parameters of organic pores can be regarded as an index for evaluating the quality of shale reservoirs.

Reservoir characteristics of different shale lithofacies and their effects on the gas content of Wufeng-Longmaxi Formation, southern Sichuan Basin, China

Various shale lithofacies differ significantly in terms of gas content and pore structure characteristics. In this study, FE-SEM, low-pressure gas adsorption (LPGA), in-situ reservoir water saturation restoring, and high-pressure (0–51Mpa) methane adsorption were conducted to systematically characterize pore structure and evaluate the gas content of different shale lithofacies in the Wufeng-Longmaxi Formation, southern Sichuan Basin. The mineral compositions identified four shale lithofacies, and pores are abundant in siliceous shale and mixed shale. Siliceous shale has the largest pore volume (PV) and specific surface area (SSA), averaging 0.0310 cm3/g and 25.827 m2/g, respectively. However, the PV and SSA are lowest in argillaceous shale, averaging 0.0217 cm3/g and 18.734 m2/g, respectively. Water saturation is positively correlated with clay minerals, and argillaceous shale possess the highest water saturation of 60% due to the highest clay content. The supercritical Dubinin-Astakhov (S-DA) excess adsorption model predictions deviated less from the measured data and fitted well. The shale adsorption capacity are dominated by TOC content and total SSA. However, water and temperature have an inhibitory activity on adsorption capacity, with the adsorption capacity of water-bearing shales decreasing by 28%∼81% at a water saturation of 30%∼65% compared to dry shales. As the temperature increased from 40 °C to 80 °C, the methane adsorption capacity decreased from 3.95 to 2.79 m3/t, a 29% decrease. The shale gas content prediction models were established and extrapolated into the functions of reservoir depth. Deep shale gas reservoirs are dominated by free gas, accounting for over 90% at 5000 m. Siliceous shale has the highest gas content, followed by mixed shale, argillaceous-siliceous shale, and argillaceous shale. It is estimated that siliceous shale has a three-fold higher gas content than argillaceous shale. Siliceous and mixed shale are favorable reservoirs for shale gas exploration and development due to their high gas contents and low water saturation.

Effects of Inorganic Minerals and Kerogen on the Adsorption of Crude Oil in Shale

Shale oil stored in the shale system occurs mainly in adsorbed and free states, and ascertaining the amount of adsorbed crude oil in shale is a method of ascertaining its free oil content, which determines the accuracy of shale oil resource evaluation. Both inorganic minerals and kerogen have the ability to adsorb crude oil, but there is controversy surrounding which plays the greatest part in doing so; clarifying this would be of great significance to shale oil resource evaluation. Therefore, in this study, the evolution states of inorganic minerals and kerogen in shale were changed using pyrolysis, and the adsorbents were prepared for crude oil adsorption experiments, to explore the effects of inorganic minerals and kerogen on the crude oil adsorption of shale. The results showed that the differences in kerogen’s structural units and content in organic-rich shale (TOC = 1.60–4.52%) had no obvious effects on its crude oil adsorption properties. On the contrary, inorganic minerals, as the main body of shale, played a dominant role in the adsorption of crude oil. The composition and evolution of the inorganic minerals controlled the surface properties of shale adsorbents, which is the main reason for the different crude oil adsorption properties of the different types of adsorbents. The results of this study are helpful in improving our understanding of the performance and mechanisms of shale in adsorbing crude oil and promoting the development of shale oil resource evaluation.

Experimental investigations of CO2 adsorption behavior in shales: Implication for CO2 geological storage

Injecting CO2 into shale reservoirs has dual benefits for enhancing gas recovery and CO2 geological sequestration, which is of great significance to ensuring energy security and achieving the “Carbon Neutrality” for China. The CO2 adsorption behavior in shales largely determined the geological sequestration potential but remained uncharted. In this study, the combination of isothermal adsorption measurement and basic petro-physical characterization methods were performed to investigate CO2 adsorption mechanism in shales. Results show that the CO2 sorption capacity increase gradually with injection pressure before reaching an asymptotic maximum magnitude, which can be described equally well by the Langmuir model. TOC content is the most significant control factor on CO2 sorption capacity, and the other secondary factors include vitrinite reflectance, clay content, and brittle mineral content. The pore structure parameter of BET-specific surface area is a more direct factor affecting CO2 adsorption of shale than BJH pore volume. Langmuir CO2 adsorption capacity positive correlated with the surface fractal dimension (D1), but a significant correlation is not found with pore structure fractal dimension (D2). By introducing the Carbon Sequestration Leaders Forum and Department of Energy methods, the research results presented in this study can be extended to the future application for CO2 geological storage potential evaluation in shales.

The influencing factors of gas adsorption behaviors in shale gas reservoirs

The adsorption state is one of the main states for shale gas occurrence, and the gas adsorption behavior in shale directly affects shale gas content under reservoir conditions. This paper provides a comprehensive literature review on shale gas adsorption behavior and its affecting factors that have been developed in recent years. Influence factors of gas adsorption behavior are examined, including total organic carbon content (TOC), organic matter type, organic matter maturity, minerals and clay minerals, moisture content, pore characteristics and other characteristics of the shale itself. The characteristics of gas adsorption behavior under high temperature and pressure conditions showed that adsorption behaviors were difficult to describe by the Langmuir equation. This review indicates that shale contains higher organic matter content and organic matter maturity and has a higher adsorption capacity. The adsorption capacity with type III kerogen is higher than that for type II or type I. Clay minerals can provide free space for gas adsorption and promote adsorption. Normally, as the moisture content increased, adsorption capacity decreased. Micro pores provided a larger specific surface area for gas adsorption. As the temperature increased, the adsorption capacity decreased. As the pressure increased, shale adsorption characteristics showed two different behaviors as follows: one obeyed the Langmuir equation, and the other presented an inverted, U-shaped, single-peak distribution. However, there are some controversies surrounding adsorption, especially regarding the aspects of clay minerals, water content, pore characteristics, etc. The key is that the mechanism of adsorption in shale is unclear. There will be many new challenges in the field of shale gas adsorption research. Such challenges include studying the organic matter chemical structure, understanding the interaction between organic matter and clay minerals and how they affect adsorption, clarifying gas adsorption behavior changes, predicting favorable areas of adsorbed gas with the coupling of reservoir temperature and pressure, and building a better theory and model of shale gas adsorption.

Quantitative characterization of methane adsorption in shale using low-field NMR

Quantification of methane content in shales is a critical parameter for estimation of their potential gas production capacity. Traditional gravimetric methods for estimation of this quantity are sensitive only to adsorbed methane and are difficult to apply either to intact shale rock cores or via field measurements. Here non-invasive low-field nuclear magnetic resonance (LF-NMR) is applied to quantify excess methane adsorption capacity in two intact shale rock plugs at pressures up to 150 bar; validation is provided against destructive gravimetric methods performed on fragments from the same shale rock plugs. The resultant NMR transverse relaxation time (T2) distributions contain three distinct peaks (referred to as peaks P1 – P3) which are allocated to adsorbed methane in organic pores, methane constrained to inorganic pores and bulk methane located predominately in fractures, respectively. The area of peak P1 is observed to increase with pressure up to 100 bar, after which it reaches a plateau, whilst the area of peaks P2 and P3 both increase linearly with pressure up to 150 bar. The most accurate estimate of excess methane adsorption capacity is obtained via a combination of an overall system mass balance and the methane located in inorganic pores and fractures (peaks P2 and P3, respectively), where excellent agreement is produced with corresponding gravimetric measurements for both shale samples studied.

Methane absorption of coal-measure shales with and without pore water from the Qinshui Basin, North China: Based on high-pressure methane absorption experiments

The coal-measure shale in the Qinshui Basin, North China has a high thermal maturity and a huge shale gas resource, but studies related to its gas-bearing property (GBP) are lack. In this paper, shale samples taken from the carboniferous coal-measure strata in the Yangquan block of Qinshui Basin were mainly investigated on their pore water contents and occurrence characteristics, and their high-pressure methane adsorption capacities under the dry and moist conditions. The results show that the pore water in the shale is in an ultra-low saturation state, occurring mainly in clay minerals (91% on average), significantly decreases its effective pore structure parameters, especially the nonmicropore specific surface areas (by 70.21% on average), and reduces its methane adsorption capacity (by 33% on average at 30 °C), with the adsorbed methane occurring mainly in micropores and controlled by the TOC content. The adsorption of methane on the shale is an exothermic process, and both the shale adsorption capacity and adsorbed methane density are reduced with increasing temperature. Pore water not only has a competitive adsorption with methane, but also weakens the adsorbed methane inter-molecular interaction forces, decreasing the methane adsorption capacity, especially under the low temperature and pressure conditions. The GBP models of a selected shale under the dry and moist conditions further indicate that pore water also decreases the adsorbed gas percentage to some extent, especially at a burial depth < 1500 m, and the adsorbed gas is dominant in the shale. These GBP characteristics of coal-measure shale should pay a great attention in the future exploration and development of shale gas in the Qinshui Basin.

Adsorption characteristics and thermodynamic analysis of shale in northern Guizhou, China: Measurement, modeling and prediction

The Lower Cambrian Niutitang Formation shale is the principal organic-rich shale formation in the northern Guizhou Province of China, which has great shale gas development prospects. In this study, the isothermal adsorption data from 26 shale samples from Niutitang Formation in northern Guizhou were obtained through the isothermal adsorption experiment of self-sampled specimens, along with published data. On this basis, we analyzed the control effects of temperature and physical parameters on adsorption capacity. An adsorption model with two new physical meaning parameters was constructed, and the accuracy of the model was validated. In addition, the isosteric enthalpy of adsorption in shale was further calculated, and the factors that affected the isosteric enthalpy were discussed. The results showed that the isosteric enthalpy decreased with an increase in temperature, and increased with an increase of TOC, but was controlled at a higher TOC. TOC-normalized heat revealed a more obvious segmental change rule for thermal maturity. Finally, we provided a new method to predict adsorption isotherms at other temperature conditions through the isosteric enthalpy of adsorption, and obtained better prediction results. This study provided a new insight for further understanding of shale adsorption characteristics from the perspective of thermodynamics.

Influence of Organic-Inorganic Composition on the Adsorption of Niutitang Formation Shale in Huijunba Syncline

To study the influence of different organic-inorganic composition on the adsorption in shale, taking the Niutitang Formation shale in the Huijunba syncline in southern Hanzhong as the research object, based on acid treatment to extract kerogen and wet chemicals. Extracting mineral components by oxidation method, a series of isothermal adsorption experiments were carried out on the original rock, kerogen, and mineral components of the samples. Through the three-dimensional Langmuir model fitting and adsorption thermodynamic calculation method, the adsorption thermodynamic parameters such as the isometric heat of adsorption and the standard adsorption entropy are obtained. The research results show that organic matter is the primary factor affecting the methane adsorption of shale and clay minerals also affect the adsorption to a certain extent. When the burial depth is relatively shallow, diagenesis has a promoting effect on the total amount of adsorption. As the depth increases, the diagenesis will turn into an inhibitory effect on the total amount of adsorption. Through the component weighting method, the lower limit ratio of the adsorbed amount of organic matter to the total amount in the shale is 29.3%~46.7% when the depth reaches to 3000 m, while the upper limit ratio of the adsorption of mineral components is 66.4%~73.6%.

Molecular Simulation Analysis of Methane Adsorption Micromechanisms and the Impact of Water Saturation on Methane Adsorption in Transitional Shale

Abstract Adsorption of gas is one of the ways that shale gas exists in the transitional shale (TS). The adsorption mechanism and the impact of water saturation on methane adsorption affect the estimated accuracy of the gas in place (GIP). This work constructs a TS molecular model comprising type III kerogen, kaolinite, illite, and quartz by using the molecular simulation (MS) according to the physical properties of the TS components. This is verified by the gas adsorption experiments of the TS and its components. The study establishes the methane adsorption model on the TS surface, the impact of the TS with varying water saturation on methane adsorption, and microscopic mechanisms of the TS methane adsorption. The experimental and simulated results show that it is feasible to construct a TS molecular model based on TS’s realistic porosity and density. Methane molecules in different mineral components of the TS are not characterized by monomolecular layer adsorption, mainly including micropore filling, transitional phase adsorption, and monomolecular layer adsorption. The transitional phase layer includes the strong adsorption layer (SAL), adsorption layer trough (ALT), and weak adsorption layer (WAL). Micropore filling and transitional phase adsorption coexist in the kerogen of the TS, and transitional phase adsorption primarily occurs in the illite of the TS. Kaolinite and quartz of the TS are featured with monomolecular layer adsorption. Moreover, quartz does not increase the pore space under high pressure because of stable silicon-oxygen chemical bonds. The chemical bonds in the kerogen and clay of the TS are relatively plastic, yielding the larger pore space under high pressure. Moreover, when water saturation exceeds 30% in the TS, water molecules cover the TS pore surface, affording the minimal methane adsorption capacity (MAC). In short, the micromechanisms of methane adsorption are determined by the TOC, adsorption model, water saturation, pressure, and isosteric heat of the TS components. The TS model can improve the accuracy of methane adsorption simulation and better understand the micromechanisms of methane adsorption. The establishment of the TS model and the impact of water saturation on methane adsorption also improves the estimated accuracy of the GIP.

On the prediction of methane adsorption in shale using grey wolf optimizer support vector machine approach

With the advancement of technology, gas shales have become one of the most prominent energy sources all over the world. Therefore, estimating the amount of adsorbed gas in shale resources is necessary for the technical and economic foresight of the production operations. This paper presents a novel machine learning method called grey wolf optimizer support vector machine (GWO-SVM) to predict adsorbed gas. For this purpose, a data set containing temperature, pressure, total organic carbon (TOC), and humidity has been collected from several sources, and the GWO-SVM model was created based on it. The results show that this model has R-squared and root mean square error equal to 0.982 and 0.08, respectively. Also, the results ensure that the proposed model gives an excellent prediction of the amount of adsorbed gas compared to previously proposed models. Besides, according to the sensitivity analysis, among the input parameters, humidity has the highest effect on gas adsorption.

Adsorption Characteristics and Pore Structure of Organic-Rich Shale With Different Moisture Contents

A moisture equilibration test has been designed to study the pore structure and adsorption capacity of organic-rich shale with different moisture contents. Five humidity environments were artificially controlled to obtain shale samples with different moisture contents. With the moisture equilibration test and N2 adsorption/desorption, the differences in pore structure of samples with different moisture contents were compared and analysed. The results showed that the diameter of 2–10 nm pores decreased with increasing humidity and that the moisture adsorption characteristics conformed to the GAB adsorption model. It is proposed that when moisture enters a sample, monolayer adsorption will first occur because moisture is preferentially adsorbed on the pore surface with strong hydrophilicity, filling in the relatively small pores. Mesopores and micropores play a major role in water adsorption. With increasing humidity, capillary condensation of moisture gradually occurs in pores. Based on the methane isothermal adsorption test of shale samples with different moisture contents, a quantitative linear relationship between the moisture content and methane adsorption capacity of shale samples has been established. It has been determined that the methane adsorption capacity of shale in underwater conditions is less than that of dry samples, and that the rate of decline in the adsorption capacity of different samples under dry and water balance conditions varies greatly. The distribution characteristics of clay minerals are the main controlling factor of the hydrophilicity of shale, which has a certain guiding significance for further accurate evaluation of shale adsorption gas reserves.

Micropore Structural Characteristics and Influence Factors of Triassic Shale Gas Adsorption in the Ordos Basin

Continental shale is investigated for potential shale gas reservoirs in the Tongchuan area, southern Ordos Basin. The kerogen macerals of Upper Triassic Chang 7 Shale are vitrinite 28–43%, exinite 4–7%, and inertinite 52–69%, and Ro is 0.85–0.88%, and the kerogen type is II. The total organic carbon (TOC) content is 9.75–29.92%, free hydrocarbon (S1) is 3.21–12.14%, pyrolysis hydrocarbon (S2) is 41.86–165.39%, and maximum pyrolysis temperature (Tmax) is 439–445°C. The mineral composition is mainly dominated by quartz 3.94–43.27%, followed by feldspar 9.65–30.07% and clay minerals 13.46–59%. Illonite/smectite (I/S) is the main clay mineral, accounting for 47–69%. The liquid nitrogen adsorption curve showed that the pore types were tubular and plate-like. The pores are mainly microporous (&amp;lt;2 nm) and mesoporous (2–50 nm) in size. Isothermal adsorption results show that Langmuir volume (VL) is 2.06–5.57 cm3 g−1, Langmuir pressure (PL) is 2.16–3.28 MPa, and shale adsorption capacity is small and easy to desorb. A quartz content less than 25% is negatively correlated with the specific surface area (SSA); otherwise, it is positively correlated. A clay mineral content less than 45% is negatively correlated with SSA; otherwise, it is positively correlated. The relationship between the carbonate content and pore structure is not obvious. Pyrite content less than 2% is positively correlated with SSA; otherwise, it is negatively correlated. The SSA is positively correlated with TOC, inertinite, and exinite and negatively correlated with vitrinite. The adsorbed gas content is positively correlated with the TOC content, SSA, inertinite content, and exinite content and negatively correlated with vitrinite.

The Distribution of Gas Components within a Shale System and Its Implication for Migration

Experimental studies on the desorption and adsorption of shale are conducted extensively and used for in-depth research on shale gas components and isotopic components. However, there is little systematic research aimed at a given shale stratum. This study takes the Chang-7 shale of the YC23 Well in the Ordos Basin as the research object, and attempts to obtain a full understanding of the distribution characteristics of different gas components, and to explore the migration ability of different gas components. In this study, Chang-7 shale gas in Well YC23 can be sorted into three categories: generated gas, retained gas and accumulated gas. Geochemical parameters including TOC, S1 and S2 are used to evaluate the generated gas, and the fractionation of hydrocarbon components is used to distinguish retained gas and migrated gas. The fractionation of non-hydrocarbon components as well as carbon isotopes is also analyzed and discussed. This study confirms that shale gas in different locations has unique gas components due to gas migration.

STUDY OF THE INTERACTION BETWEEN MICROSTRUCTURE AND MACROSCOPIC BEHAVIOR FOR HYDRAULIC FRACTURING AREAS DURING SHALE GAS EXTRACTION

Horizontal drilling is the major method of shale gas extraction, and hydraulic fracturing improves the gas production effectively. However, as the main gas migration channel, shale microstructures, such as the natural fractures and pores, are extremely complicated, and it is difficult to characterize them quantitatively by conventional approaches. Besides, the microstructural evolution of the hydraulic fracture (HF) area is more intricate. In order to quantitatively characterize the evolution of shale microstructure after hydraulic fracturing, and to investigate the contribution to the gas extraction process, a fully coupled fractal thermal–hydrological–mechanical permeability model is proposed. And the interaction of shale microstructure, thermal–hydrological–mechanical effects, and gas permeability in the HF area is also quantitatively investigated. Shale thermal conduction, gas pressure, and adsorption–desorption effect are defined as functions of the effective stress responsible for shale matrix deformation, and operate directly on shale porosity, which induces changes in shale microstructure, including the shale fractal dimension (for characterizing the density of natural fractures in shale) and the maximum fracture length. Multiphysical effects have a major impact on gas seepage, and directly affecting the permeability. Furthermore, compared to the widely used cubic permeability model, this model is significantly superior in analyzing the permeability evolution in the hydraulically fractured area, and the reliability is verified by the production data from the Marcellus Shale.

Hybrid Pore-Scale Adsorption Model for CO2 and CH4 Storage in Shale

Making reliable estimates of gas adsorption in shale remains a challenge because the variability in their mineralogy and thermal maturity results in a broad distribution of pore-scale properties, including size, morphology and surface chemistry. Here, we demonstrate the development and application of a hybrid pore-scale model that uses surrogate surfaces to describe supercritical gas adsorption in shale. The model is based on the lattice density functional theory (DFT) and considers both slits and cylindrical pores to mimic the texture of shale. Inorganic and organic surfaces associated with these pores are accounted for by using two distinct adsorbate–adsorbent interaction energies. The model is parametrized upon calibration against experimental adsorption data acquired on adsorbents featuring either pure clay or pure carbon surfaces. Therefore, in its application to shale, the hybrid lattice DFT model only requires knowledge of the shale-specific organic and clay content. We verify the reliability of the model predictions by comparison against high-pressure CO2 and CH4 adsorption isotherms measured at 40 °C in the pressure range 0.01–30 MPa on four samples from three distinct plays, namely, the Bowland (UK), Longmaxi (China), and Marcellus shale (USA). Because it uses only the relevant pore-scale properties, the proposed model can be applied to the analysis of other shales, minimizing the heavy experimental burden associated with high-pressure experiments. Moreover, the proposed development has general applicability meaning that the hybrid lattice DFT can be used for the characterization of any adsorbent featuring morphologically and chemically heterogeneous surfaces.

Influences of microwave irradiation on pore, fracture and methane adsorption of deep shale

In order to better understand the feasibility of enhancing shale gas recovery by microwave irradiation, the influences of microwave irradiation on the pore, fracture, and methane (CH4) adsorption pertaining to shale gas production of a deep shale were fully addressed. A combination of multiple characterization methods was used, including pyrolysis, X-ray diffraction, back-scattered scanning electron microscope, probe molecule adsorption, steady-state permeability, X-ray computed tomography, and gravimetric method for measuring CH4 adsorption. Results show that microwave irradiation has no obvious impact on micropore but decreases mesoporous surface area, and volume of the shale matrix. It particularly reduces the adsorption pores for accommodating CH4 with the diameter of less than 8 nm. The nanoscale pore structure evolution is mainly associated with alterations in organic matter and inorganic minerals of the deep shale after microwave irradiation. Microwave irradiation induces the decomposition, cracking, shift, stripping and formation of minerals, as well as the formation of organic matter. Furthermore, it significantly increases fractures paralleling to bedding planes of the deep shale due to thermal stress generated within various minerals. These newly formed fractures dramatically increase the porosity and permeability of the deep shale. Finally, microwave irradiation significantly decreases the maximum CH4 adsorption capacity of the deep shale by 16.38%. In summary, this study put forward a novel method for enhancing shale gas production via simultaneously promoting CH4 migration and reforming reservoirs under controlled microwave field.

AFM characterization of surface mechanical and electrical properties of some common rocks

The characterization of micro-surface mechanical and electrical properties of the natural rock materials remains inadequate, and their macroscopic performance can be better comprehended by investigating the surface properties. With this purpose, the present research focuses on characterizing the micro-surface morphology, Derjaguin-Muller-Toporov (DMT) modulus, adhesion, and potential of granite, shale, and limestone by employing the atomic force microscope (AFM) as a pioneer attempt. The results show that the micro-surface morphology of the rock fluctuates within hundreds of nanometers, among which the granite micro-surface is comparatively the smoothest, followed by limestone. The morphology of the shale is the roughest, indicating that the regional difference of shale micro-surface is dominant. The distribution of the adhesion on rock micro-surface is uneven; the average adhesion of eight measuring areas for shale is 23.93 nN, accounting for three times of granite and limestone, while the surface DMT modulus of shale is relatively lower than granite and limestone. It is inferred from the obtained results that higher surface adhesion is helpful to the gas adsorption of shale, and the lower surface DMT (elastic) modulus is useful to the formation of fractures and pores. Thus, these two are the micromechanical basis of shale gas adsorption. Additionally, introducing a method to reduce the surface adhesion will benefit the exploration of unconventional resources such as shale gas. The micro-surface of the three types of rocks all shows electricity, with average potential ranging from tens of millivolts to hundreds of millivolts. Besides, the micro-surface potential of the rocks are heterogeneous, and both positive and negative points can be found. The existence and uneven distribution of micro-surface potential provide a robust physical basis for the electromagnetic radiation generated by rock fracture under loading. This study offers a new method for revealing the adsorption characteristics of unconventional gas reservoir rocks and the electromagnetic radiation mechanism of the rock fracture.

Influence of Particle Size on the Low-Temperature Nitrogen Adsorption of Deep Shale in Southern Sichuan, China

Pore characteristics are one of the most important elements in the study of shale reservoir properties and are a key parameter for the evaluation of the potential of shale oil and gas resources. Low-temperature nitrogen adsorption is a common laboratory method that is used to characterize the pore structure of shale. However, the effect of shale’s particle size on the experimental results of the nitrogen adsorption of deep shale samples is still unclear. In this paper, using deep shale samples of different mesh sizes from the Luzhou Block as an example, we studied the effect of particle size on the pore structure of deep shale, as characterized by nitrogen adsorption experiments. The results showed that the pore volume of deep shale is mainly distributed in the mesoporous range, with a pore size ranging from 2 to 20 nm. The pore volume, as measured by nitrogen adsorption, increases slowly as the particle size decreases and then it increases rapidly. The particle size of shale has no obvious effect on the measurement of the specific surface area. The fractal dimension of deep shale gradually increases as the particle size of the shale samples increases and the smaller the particle size, the higher the correlation coefficient, R2, of the fractal dimension fitting. In this paper, different recommended sizes are given for selecting suitable particle sizes in nitrogen adsorption experiments on deep shale with different structural parameters, which will increase the accuracy of the study of the pore structure of deep shale.

Experimental study on the isothermal adsorption of methane gas in natural gas hydrate argillaceous silt reservoir

Gas hydrate occurs in hydrate reservoirs in a solid form. At present, the conventional exploitation method is to decompose solid hydrate and then extract the resulting gaseous gas. Therefore, the occurrence law of gas in a reservoir is of great significance for the study of gas hydrate seepage and productivity. Adsorption, as an important occurrence mode, has been widely concerned in the research on shale reservoirs. However, the adsorption problem in hydrate reservoirs has not received enough attention. In this paper, the existence of adsorption in a hydrate reservoir has been experimentally confirmed for the first time. Based on the argillaceous silt of a natural gas hydrate reservoir in the South China Sea, the pore structure and adsorption characteristics of argillaceous silt were experimentally studied, and the results were compared with those of typical shale reservoirs. The modified Langmuir and Dubinin-Radushevich equations were used to fit the adsorption data, and the suitable adsorption model of argillaceous silt was established and optimized. The results showed that the inhomogeneous slit pores are dominant in argillaceous silt, and they are formed by the accumulation of lamellar particles. Compared with shale, the adsorption capacity of argillaceous silt is weak under the same conditions. However, adsorption is a spontaneous exothermic reaction, and the ambient temperature of argillaceous silt is much lower than that of shale. Therefore, it is possible for argillaceous silt to achieve an adsorption capacity comparable to that of shale. The modified Langmuir model can be used to simulate argillaceous silt adsorption at low pressure, while under medium and high pressures, the modified Dubinin-Radushevich model performs better. The adsorption capacity of argillaceous silt is affected by moisture. When the water content is 20%, the Langmuir adsorption capacity and the Dubinin-Radushevich maximum adsorption capacity decreases by 21.88% and 13.67%, respectively, which is far less than the influence of moisture on shale adsorption, as reported in the literature. Cited as: Qi, R., Qin, X., Lu, C., Ma, C., Mao, W., Zhang, W. Experimental study on the isothermal adsorption of methane gas in natural gas hydrate argillaceous silt reservoir. Advances in Geo-Energy Research, 2022, 6(2): 143-156. https://doi.org/10.46690/ager.2022.02.06