Adsorption Capacity Of Shale Research Articles

Reservoir Characteristics of Marine–Continental Transitional Taiyuan Formation Shale and Its Influence on Methane Adsorption Capacity: A Case Study in Southern North China Basin

To further study the reservoir characteristics and adsorption capacity of the Taiyuan Formation shale in the South North China Basin (SNCB), the pore structure and adsorption capacity of shale are discussed using various analysis tests, including elemental geochemistry, organic geochemistry, mineral composition, low-temperature nitrogen adsorption (LTNA), and methane adsorption experiments. The results indicate that the Taiyuan Formation shale formed in a poor oxygen and anaerobic sedimentary environment in still water. The average value of total organic carbon (TOC) content is 2.37%. The organic matter type mainly consists of type III kerogen. The vitinite reflectance (Ro) ranges from 3.11% to 3.50%. The clay mineral content varies greatly, averaging at 40.7%, while the quartz content averages at 37.7%. The Taiyuan Formation shale mainly develops interparticle (InterP) pores, followed by organic pores, intraparticle (IntraP) pores, solution pores, and microfractures. BET specific surface area (SSA) is between 9.47 m2/g and 22.14 m2/g, while pore volume (PV) ranges from 0.0098 cm3/g to 0.022 cm3/g, indicating favorable conditions for shale gas storage. According to the results of the CH4 adsorption experiment, Langmuir volume from Taiyuan Formation shales exhibits 1.35~4.30 cm3/g, indicating excellent adsorption capacity. TOC content shows a positive correlation with both Langmuir volume and BET SSA from Taiyuan Formation shales, suggesting that TOC plays a crucial role in controlling microscopic pores and gas adsorption capacity. Organic matter enhances the shale adsorption capacity by providing abundant pore SSA. Due to formation compaction, the pore size of clay minerals decreases, leading to an increase in pore SSA, while kaolinite exhibits weak hydrophilic ability. Consequently, with the increase in clay minerals and kaolinite content, the shale adsorption capacity is enhanced to a certain extent. However, an increase in the carbonate mineral content may result in a decrease in the proportion of clay minerals, therefore reducing the CH4 adsorption capacity of shale.

Comparative Study of the Characteristics of Lower Cambrian Marine Shale and Their Gas-Bearing Controlling Factors in the Middle and Lower Yangtze Areas, South China

This study comparatively analyzed the geological, geochemical, reservoir, and gas-bearing characteristics of the lower Cambrian marine shale in the Middle and Lower Yangtze regions. The main factors controlling the gas-bearing properties of the shales were identified, and the favorable and unfavorable conditions for shale gas accumulation are discussed. The results show that the organic carbon contents and thermal evolution degree of the organic matter in the lower Cambrian marine shale in the Lower Yangtze area were higher than those generally found in the Middle Yangtze area. The brittle mineral composition of the Middle Yangtze area was typically low silicon and high calcium, whereas the Lower Yangtze area was characterized by high silicon and low calcium. The development of micropores in the Lower Yangtze area was poorer than in the Middle Yangtze area, with the organic pores being particularly underdeveloped. The adsorption capacity of shale in the Lower Yangtze area was obviously higher than in the Middle Yangtze area. It was considered that the organic carbon content, thermal evolution degree, and molecular structure of kerogen were the main factors that controlled the adsorption properties of the shale. In addition, the Lower Yangtze area suffered a stronger tectonic transformation and frequent magmatic activity, and the preservation conditions were inferior to those in the Middle Yangtze area.

Response of pore network fractal dimensions and gas adsorption capacities of shales exposed to supercritical CO2: Implications for CH4 recovery and carbon sequestration

The injection of CO2 into shale reservoirs potentially increases rates and masses of CH4 recovery and simultaneously contributes to the sequestration of CO2. At typical reservoir conditions (T≥31.08 °C, P≥7.38 MPa) the CO2 will be supercritical. We compile, analyze, and supplement experimental data of shales from several basins across China, and use X-ray diffraction, scanning electron microscopy and low-pressure gas adsorption to characterize variations in shale pore structure before and after supercritical CO2 (ScCO2) treatment, and supplement these with CH4/CO2 adsorption experiments to characterize changes in shale adsorption capacity. The results show that clay and carbonate contents significantly decrease, and the relative content of quartz is increased after ScCO2 treatment. Pore structure changes significantly after ScCO2 treatment, with the majority of the shales showing a decrease in total specific surface area and total pore volume and an increase in average pore size — indicating the transformation of some micropores and smaller mesopores into mesopores and macropores. After ScCO2 treatment, the experimentally derived absolute adsorption volumes of both CH4 and CO2 decrease, and the volumes of both CH4 and CO2 fitting a Langmuir isotherm decrease with an increase in treatment pressure and increase with an increase in temperature. The adsorption selectivity factors αCO2/CH4 all remain greater than 1 with αCO2/CH4 primarily controlled by the pore structure. The fractal dimension is positively correlated with Langmuir volume and negatively correlated with Langmuir pressure while the fractal dimensions are negatively correlated with αCO2/CH4. The selectivity factor αCO2/CH4 decreases rapidly above a fractal dimension threshold (D1>2.65, D2>2.80). This paper further reveals critical interactions between ScCO2 and shale and defines controls on and of pore structure and adsorption capacity to speculate on physical and chemical storage mechanisms of CO2 in shale reservoirs. This provides several theoretical bases for shale gas recovery and the sequestration of CO2.

Determination of adsorption parameters in shale gas resource/reserve calculation: Case study of Wufeng Formation–Longmaxi Formation in the Sichuan Basin

In the calculation of shale gas resources/reserves, isothermal adsorption parameters are mainly determined by dry sample data at the laboratory temperature, and the regression effect of total organic carbon content (TOC) isothermal adsorption parameters is poor. Based on the physical significance of key parameters in Langmuir and Henry adsorption models, the problems in determining the isothermal adsorption parameters in the calculation of shale gas reserves/reserves are analyzed by taking the marine shale in the Upper Ordovician Wufeng Forming–Lower Silurian Longmaxi Formation in the Sichuan Basin as an example. Based on a large number of measured isothermal adsorption data, the effects of TOC, temperature and water saturation on the shale gas adsorption parameters are analyzed. The influence model of TOC, temperature and water saturation on isothermal adsorption parameters of shale gas is established, and a novel method for calculating the adsorption parameters of shale gas from under experimental conditions to original reservoir conditions is proposed. The results are obtained as follows. First, there are problems in the calculation of shale gas resources/reserves, such as poor and contradictory fitting relation between isothermal adsorption parameters and TOC, difficulty in the conversion of Van't Hoff equation, and difficulty in direct application of water saturation (Sw) in resource/reserves calculation. Second, the problem of poor direct fitting relation between Langmuir pressure (pL) and TOC is solved by integrating the Langmuir adsorption model with the Henry adsorption model and by establishing a new parameter – Henry constant a for methane adsorption capacity of shale. Third, when Sw<40%, the Langmuir volume (VL) is linearly negatively correlated with Sw; when Sw<20%, a is constant relatively; by establishing the relationship between the normalized absolute adsorption capacity and Sw (<50%) under the pressure exceeding 30 MPa, the effect of Sw on the isothermal adsorption capacity can be calculated. Fourth, the in-situ stress in the Wufeng Formation–Longmaxi Formation shale reservoir affects the adsorption capacity of shale. For shale reservoirs with the same TOC, the higher the in-situ stress, the smaller the VL and a values. Under high pressure (>30 MPa), the effect of Sw on the methane adsorption capacity of shale shows a similar trend, and the effect of water molecules on the adsorption capacity on shale pore surface is constant. It is concluded that the proposed novel method for determining the isothermal adsorption parameters of shale with different TOC, temperature and water saturation conditions provides a technical support for the accurate calculation of shale gas resources/reserves and contributes to the scientific development of shale gas industry.

Enrichment characteristics of deep shale gas in tectonically complex regions of the southeastern sichuan basin, China

In recent years, breakthroughs have been made in deep shale gas exploration in the Wufeng-Longmaxi formations in the complex tectonic region of the Sichuan Basin and southeastern margin, indicating promising prospects for exploration and development. This study focuses on the Nanchuan area of the complex tectonic region of the southeastern Sichuan Basin margin, using data from drilling wells and experimental analysis tests to investigate deep shale gas enrichment characteristics, particularly the effects of changes in the formation environment such as formation temperature and pressure on deep shale gas enrichment. The study concludes that: (1) The dominant sedimentary phase zone is the basis for hydrocarbon formation in shale gas reservoirs, with the Wufeng Formation–the first member of Longmaxi Formation in the study area—formed in a deep-water shelf sedimentary environment with high-quality shale development, which provides favorable material conditions for the formation of shale gas reservoirs. (2) Organic carbon content controls the degree of development of nanoscale organic matter pores, and the high-pressure-ultra-high-pressure environment helps maintain pores and improve the physical properties of deep shale. (3) Deep shale gas exhibits typical geological characteristics of high temperature, high ground stress, and exceptionally low permeability. The study finds the influence of temperature on the adsorption capacity of shale is more significant than that of pressure, and deep shale gas is primarily free gas. High pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (4) Gas diffusion is complex, with high temperature increasing the diffusion of gas, aggravating the migration and escape of gas, while high pressure can slow down or inhibit gas flow, which is beneficial to shale gas preservation. (5) The burial depth and pressure coefficient show a positive correlation, and the burial depth has a more significant effect on the pressure coefficient of syncline shale gas, indicating that preservation conditions of deep syncline shale gas reservoirs are becoming better. Residual syncline core with larger depths, inner-sag uplift, and slopes with reverse faults can be favorable targets for shale gas exploration in complex tectonic zones.

Influence of Water on the Methane Adsorption Capacity of Organic-Rich Shales and Its Controlling Factors: A Review

A typical feature of shale gas reservoirs is that they contain a significant amount of adsorbed gas. The evaluation and prediction of adsorbed gas play important roles in shale gas exploration and development. However, the presence of water in shale reservoirs makes this work more difficult. In recent years, research related to the occurrence and distribution of water in shales and its effect on methane adsorption have become a prominent issue. In this paper, the factors controlling water in shale nanopores and its influence on methane adsorption were systematically reviewed. It is revealed that the connate water content in shales and their water absorption capacity vary widely, and both are mainly related to the organic matter contents and properties and mineral compositions. The water absorption capacity of organic matter in shales is mainly affected by its nanopore content, structure and surface chemical properties (such as the type and amount of oxygen-containing functional groups), which are jointly constrained by its kerogen type and maturity. Even under moist conditions, the organic matter in shales still shows a strong methane adsorption capacity, although the water decreases the adsorption capacity to some extent. The hydrophilicity of different minerals in shales varies greatly, but the type and amount of clay minerals are the main factors affecting the adsorbed water content or water adsorption capacity of shales. The nanopore structure and characteristics of shales, such as the pore type, specific surface area, pore size distribution and heterogeneity, directly impact the occurrence and distribution of water. The competition for adsorption between water and methane at some adsorption sites is the main mechanism for the reduction in the methane adsorption capacity of moist shales. In addition, external environmental factors, such as pressure and temperature, can change the distribution and occurrence of water in shales and, thus, the influence of water on the methane adsorption capacity to a certain extent. This paper also discusses some current issues regarding the effect of water on methane adsorption capacity and highlights future research directions in this field.

Evaluation model of shale-adsorbed gas considering clay and water saturation

Shale adsorption capacity is affected by many factors including temperature, pressure, geochemical characteristics of organic matter, clay, and water saturation. The traditional calculation model of adsorbed gas content only considers the influence of temperature, pressure, and organic geochemical characteristics. The influence of clay and water saturation on adsorption capacity is seldom considered. Isotherm adsorption experiments were conducted on synthetic specimens and natural specimens with varying clay types, clay contents, and water saturations. Then, the influences of clay and water saturation on the adsorption capacity were systematically studied. The experimental results found that the order of clay adsorption capacities was smectite &gt; kaolinite &gt; chlorite &gt; illite. The multicomponent superposition rule was applicable in evaluating shale-adsorbed gas content. The total adsorption capacity was equal to the accumulation of the adsorption capacities of all types of clay and organic matter. Moisture will significantly reduce the adsorption capacity of shale. The adsorption capacities of synthetic specimens and natural specimens after being fully saturated with water were 9%–14% and 42%–61% of those in dry states, respectively. Then, a new shale-adsorbed gas evaluation model was established based on the Langmuir equation considering clay and water saturation. The calculation error of this new model was approximately 11%, which provides a new method for evaluating the adsorbed gas content of shale.

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.

Molecular Simulation of Methane Adsorption Capacity of Matrix Components of Shale.

Shale gas occurs mainly as adsorption and free gas. Among them, whether the adsorbed gas can be gradually desorbed or not is a major cause of stable and high yield. The matrix component is the main factor affecting the adsorption capacity of shale. In this paper, by simulation software named Materials Studio (MS), using Molecular Dynamics Simulation and Monte Carlo Simulation, the adsorption capacity of different matrix components under specific conditions is studied and the four models: relative concentration model, diffusion coefficient model, saturated adsorption capacity model and isosteric heat of adsorption model, are built. The simulation models show that the mineral matrix has a significant impact on the adsorption of methane molecules in shale: kerogen I &gt; smectite &gt; chlorite &gt; illite &gt; quartz. Kerogen I has the strongest adsorption capacity with high-density thick layer adsorption. Under the temperature (369.97 K) and the formation pressure (28.07 MPa) and under the condition of 6.0 nm in the cylindrical hole, excess adsorption amount of kerogen I is 13.418%, the diffusion coefficient is only 0.046 Å2/ps, saturated adsorption amount is 3.060 cm3/g, and the amount of adsorption heat is 9.598 kJ/mol. As the adsorption force on the pore wall is not as strong as the interaction repulsion force between adsorbents within a short distance, the clay minerals all have 2~4 layers of narrow layer and low-density adsorption. The adsorption thickness of the single layer is inversely proportional to its adsorption capacity, and the adsorption capacity is positively correlated with the opportunity of exposing oxygen atoms to form hydrogen bonds. Quartz has no obvious adsorption potential for methane molecules. This study is conducive to the quantitative evaluation of shale gas adsorption capacity, selection of favorable blocks and advantageous zones of shale gas reservoirs, and the improvement of development efficiency.

Thermodynamic characteristics of high-pressure CH4 adsorption on longmaxi shale subjected to supercritical CO2-water saturation

The shale-CH4 interaction after supercritical CO2 (ScCO2) injection can be well interpreted by adsorption thermodynamics study. Using a gravimetric method, the methane adsorption experiments over wide range of pressure (up to 35 MPa) and temperature (30–90 °C) were conducted on Longmaxi shale before and after ScCO2-water saturation (60days/20Mpa/70°C). In addition, low-temperature CO2 and N2 adsorption experiments were performed to analyze the variations of pore structure of shale. Results indicates that the high-pressure CH4 adsorption curves of shale exhibit obvious excess adsorption characteristics, and the excess adsorption capacity of shale to CH4 decreased after ScCO2-water saturation, which is mainly caused by the decrease of the specific surface area of shale. Comparing to Brunauer-Emmett-Teller, Dubinin-Radushkevich and Ono-Kondo models, the excess adsorption data can be well-fitted by Langmuir model through combining Henry equation. Additionally, the thermodynamic parameters of shale-CH4 adsorption pair, including the isosteric heat of adsorption, enthalpy change, Gibbs free energy change and entropy change, displayed strong dependence on adsorption capacity and temperature, and altered in varying degrees after ScCO2-water saturation, demonstrating that the shale gas recovery can be enhanced by ScCO2-water-shale interaction from the perspective of thermodynamics. This study provides a reference for CO2 enhanced shale gas recovery.

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.

The maturity of Silurian Longmaxi shale in Jiaoshiba, Sichuan Basin: as revealed by laser Raman spectroscopy

Accurate estimates of the thermal maturity of organic matter are important in studies of shale oil and gas, as these data are directly related to the genesis type of shale gas, adsorption capacity of shale and formation of organic pores in organic-rich shale. Longmaxi shale is a major shale gas exploration target in South China and a typical overmature shale gas play. Because Longmaxi shale is Silurian marine strata without vitrinites, it is difficult to determine its maturity accurately. In order to evaluate the maturity of the Longmaxi shale exactly, in this paper, solid bitumen reflectance, basin modeling and laser Raman spectroscopy analyses of solid bitumen were carried out on the shale. The solid bitumen reflectance of Longmaxi shale is range of 2.77–4.14% with a mean of 3.5%, and the corresponding equivalent vitrinite reflectance (EqVRo) is 2.6%; additional information about the maturation is provided by the basin modeling with the constraint of the maximum paleo-geothermal about 210–220 °C which was indicated by thermo-acoustic emission measurement, fluid inclusion thermometry and equivalent vitrinite reflectance. In addition, the Raman was applied to Longmaxi shale in Jiaoshiba firstly, and the Raman inter-peak interval between peak G (graphitic band) and peak D (disordered band) is range of 270–279 cm−1, which suggests that equivalent vitrinite reflectance is about 2.67% and is consistent with the results of solid bitumen reflectance, infrared spectrum and basin simulation. Approximate conclusions have been drawn from these different methods, and the thermal evolution of Longmaxi shale in Jiaoshhiba area, the largest shale gas field in China, was estimated at approximately 2.5–2.7%, which means that it has reached the overmature dry gas stage. Overall, the findings also imply that Raman spectra of pyrobitumen can be used effectively to evaluate the maturation of the marine shale without vitrinites.

Effects of gas components, reservoir property and pore structure of shale gas reservoir on the competitive adsorption behavior of CO2 and CH4

CO2 injection into shale gas reservoirs is deemed as a potential scheme to enhance CH4 recovery and achieve the ambition of carbon neutral. The insufficient research of binary gas competitive adsorption behavior at in-situ conditions of shale gas reservoirs, and the coupling control of gas components, shale properties, and pore structure on CO2 adsorption affinity limit its general application. Therefore, the competitive adsorption behavior of CO2 and CH4 at in-situ conditions is simulated using high-pressure multi-component adsorption experiments, and the effects of binary gas components, shale properties and pore structure on CO2 adsorption affinity are discussed. Subsequently, the mathematical and geological models of CO2 injection into Longmaxi shale gas reservoir enhancing CH4 recovery and achieving carbon sequestration are established based on experimental parameters and reservoir geological parameters, and the feasibility and expectation benefits are discussed. The results exhibit that selectivity coefficient of CO2 relative to CH4 (Sc) decreases with higher CO2 mole fraction, whereas it increases with higher total organic carbon content (TOC) and clay content. Both pore volume (PV) and specific surface area (SSA) have clear positive correlations with Sc. Overall, TOC is a crucial controlling factor of pore structure and adsorption capacity of shale, further, affects the adsorption affinity of CO2. The injection of CO2 into shale gas reservoir shows a promising application prospect in improving CH4 recovery and carbon emission reduction in geological and mathematical models, and the leakage risk is low after CO2 sequestration.

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.

Pore characteristics and corresponding controlling factors of the marine shale gas reservoir in the Wufeng-Longmaxi Formation of the Zhaotong shale gas demonstration area

The shale gas reservoir in the Zhaotong national shale gas demonstration area in the southern margin of the Sichuan Basin is mainly developed in the lower member of the Ordovician Wufeng Formation to the Silurian Longmaxi Formation. Shale pore characteristics are the main indicators for evaluating the quality of shale reservoirs and largely determine shale gas productivity. We have qualitatively and quantitatively analyzed pore types and structures through scanning electron microscopy, CO2/N2 adsorption and high-pressure mercury injection experiments, and nuclear magnetic resonance. The pore types of marine shale gas reservoirs in the study area mainly included organic-matter pores and clay mineral interlamellar pores. The pore diameter of the shale reservoir ranged from 0.5 to 35 nm and was concentrated in the range of 2–10 nm, and the main pores were mesopores. Total organic carbon (TOC) content was positively correlated with fractal dimension, which could be used to quantitatively evaluate the complexity and heterogeneity of reservoir pores. The contents of TOC, clay, and siliceous minerals were the main factors controlling the development of shale micropores. The contents of clay minerals and siliceous minerals determined the storage space of shale gas, whereas micropores and mesopores controlled the adsorption capacity of shale.

The effect of oil extraction on porosity and methane adsorption for dry and moisture-equilibrated shales

The porosity and methane adsorption capacity of shale used to estimate gas in place (GIP) are affected both by moisture and oil residing in the pore structure, as well as oil naturally present from maturation, which can include contaminant drilling mud fluids used for drilling. To demonstrate the impact of extractable oil on methane adsorption capacity for both dry and moisture-equilibrated shales, two overmature shales from China (SH1, SH2) and two lower mature shales from UK (BS3, GH4) have been investigated. The oils extracted from the overmature shales (<0.5 wt% TOC) are in low yield and arise from oil-based drilling mud, while the much higher yields from the lower maturity UK shales (1.1–2.5 wt% TOC) is mainly from oil generated by maturation. After extraction, minimal changes (<5%) in total nanopore volume (<100 nm) were observed for the dry over mature shales, but significant increases (95 and 176%) were observed for the dry lower maturity shales. More than 60% of the extracted oil resides in micro and mesopores, and removal could unblock the micropore necks and enlarge the accessible meso and macropore volume. Moisture contents are lower for extracted shales, with reductions of 7–37% observed. Methane equilibrium adsorption capacities increased after oil extraction for both the dry and wet shales, especially for lower maturity shales, where increases were over 200% for the wet shales. Henry’s Law was used to show that there were not significant amounts of dissolved methane in oils for the dry shales. Extracting oil from shales prior to determining the porosity and methane adsorption capacity can lead to the GIP being over-estimated for moisture equilibrated shales, particularly for oil-window shales where an overestimation of 22% was obtained for the shale investigated in this study. These findings provide a better understanding of the combined impacts of residual oil and water on GIP and avoid its overestimation.

Carbon dioxide adsorption and interaction with formation fluids of Jordanian unconventional reservoirs

Shales are mostly unexploited energy resources. However, the extraction and production of their hydrocarbons require innovative methods. Applications involving carbon dioxide in shales could combine its potential use in oil recovery with its storage in view of its impact on global climate. The success of these approaches highly depends on various mechanisms taking place in the rock pores simultaneously. In this work, properties governing these mechanisms are presented at technically relevant conditions. The pendant and sessile drop methods are utilized to measure interfacial tension and wettability, respectively. The gravimetric method is used to quantify CO2 adsorption capacity of shale and gas adsorption kinetics is evaluated to determine diffusion coefficients. It is found that interfacial properties are strongly affected by the operating pressure. The oil-CO2 interfacial tension shows a decrease from approx. 21 mN/m at 0.1 MPa to around 3 mN/m at 20 MPa. A similar trend is observed in brine-CO2 systems. The diffusion coefficient is observed to slightly increase with pressure at supercritical conditions. Finally, the contact angle is found to be directly related to the gas adsorption at the rock surface: Up to 3.8 wt% of CO2 is adsorbed on the shale surface at 20 MPa and 60 °C where a maximum in contact angle is also found. To the best of the author’s knowledge, the affinity of calcite-rich surfaces toward CO2 adsorption is linked experimentally to the wetting behavior for the first time. The results are discussed in terms of CO2 storage scenarios occurring optimally at 20 MPa.

Clarifying the Effect of Clay Minerals on Methane Adsorption Capacity of Marine Shales in Sichuan Basin, China

The effect of clay minerals on the methane adsorption capacity of shales is a basic issue that needs to be clarified and is of great significance for understanding the adsorption characteristics and mechanisms of shale gas. In this study, a variety of experimental methods, including XRD, LTNA, HPMA experiments, were conducted on 82 marine shale samples from the Wufeng–Longmaxi Formation of 10 evaluation wells in the southern Sichuan Basin of China. The controlling factors of adsorption capacities were determined through a correlation analysis with pore characteristics and mineral composition. In terms of mineral composition, organic matter (OM) is the most key methane adsorbent in marine shale, and clay minerals have little effect on methane adsorption. The ultra-low adsorption capacity of illite and chlorite and the hydrophilicity and water absorption ability of clay minerals are the main reasons for their limited effect on gas adsorption in marine shales. From the perspective of the pore structure, the micropore and mesopore specific surface areas (SSAs) control the methane adsorption capacity of marine shales, which are mainly provided by OM. Clay minerals have no relationship with SSAs, regardless of mesopores or micropores. In the competitive adsorption process of OM and clay minerals, OM has an absolute advantage. Clay minerals become carriers for water absorption, due to their interlayer polarity and water wettability. Based on the analysis of a large number of experimental datasets, this study clarified the key problem of whether clay minerals in marine shales control methane adsorption.