Adsorption Capacity Of Shale Gas Research Articles

Machine learning method for shale gas adsorption capacity prediction and key influencing factors evaluation

Shale gas plays a pivotal role in the global energy landscape, emphasizing the need for accurate shale gas-in-place (GIP) prediction to facilitate effective production planning. Adsorbed gas in shale, the primary form of gas storage under reservoir conditions, is a critical aspect of this prediction. In this study, a machine learning Gaussian process regression (GPR) model for methane adsorption prediction was established and validated using published experimental data. Five typical variables, i.e., total organic carbon (TOC), clay minerals, temperature, pressure, and moisture were considered, which were derived from the Marine shale of the Longmaxi formation in the Sichuan Basin through correlation analysis. The performance of the GPR model was compared with the widely used an extreme gradient boosting model. It turned out that our GPR model had better accuracy for predicting methane adsorption in shale with an average relative error of less than 3%. Furthermore, a variance-based sensitivity analysis method in conjunction with kernel density estimation theory was employed to conduct a global sensitivity analysis, quantifying the nonlinear influence of each variable methane adsorption. The findings indicate that TOC is the most significant factor affecting methane adsorption, while clay minerals have a limited direct impact but can enhance their influence through interactions with other influencing factors. Finally, based on the GPR model, a GIP prediction method was proposed that eliminates the need for calculating the density of the adsorbed phase. These findings are expected to extend the shale gas reserve assessment methodologies and offer valuable insight for further exploring the adsorption mechanisms of shale gas.

Geochemical and gas bearing characteristics of the marine-continental transitional Longtan shales in southern Sichuan, China

Marine-continental transitional shale, as an important shale type, gains less attention than marine and continental shale, which restricts the exploration and development process of marine-continental transitional shale gas. In this study, the Upper Permian Longtan Formation shale in the southern Sichuan Basin was taken as the research object, and the organic matter development characteristics, hydrocarbon generation ability, mineral composition, physical properties, and gas bearing characteristics of the Longtan Formation shale were systematically analyzed. In addition, the effects of organic matter abundance, maturity, and mineral components on shale gas adsorption capacity have been discussed in detail. The results show that the abundance of organic matter in the marine continental transitional shale of the Longtan Formation in southern Sichuan varies greatly, with the TOC value of the vast majority of shale being greater than 2.0%, with the carbon shale (TOC>12%) accounting for about 5%. The main type of organic matter is Type III, with part of Type II2. The maturity of organic matter is in the stage of high maturity to over maturity, which is conducive to the generation of dry gas. There is a good positive linear correlation between the reflectance of vitrinite (Ro) and the maximum thermal decomposition peak temperature (Tmax) of rock. The higher the abundance of organic matter, the greater the hydrocarbon generation potential of shale, and the carbonaceous shale shows good shale gas generation potential. The shale of the Longtan Formation is rich in clay minerals, with the highest content of the illite/smectite mixed layer. The abundance and maturity of organic matter jointlypromote the enrichment of Longtan shale gas. The enrichment of clay minerals is beneficial to shale gas adsorption, but poses a challenge to production fracturing.

Adsorption characteristics of shale gas in organic–inorganic slit pores

With the gradual advancement of shale gas exploration and development technology, shale gas has replaced conventional oil and gas as the primary energy source. As the main occurrence form of natural gas in shale reservoirs, the adsorption state is always an important research topic for evaluating the gas-bearing property of shale reservoirs and improving shale gas recovery. However, at present, there are few studies on control factors and control mechanisms of adsorbed gas in organic–inorganic slit pores, with several unexplained control factors and mechanisms. Taking Songliao Basin shale as an example, molecular simulations are employed to investigate shale gas adsorption in organic–inorganic slit pores, the graphene and kaolinite rock matrix model is employed, and molecular dynamics simulations, particularly the grand canonical Monte Carlo simulation is studied for pore sizes of 2, 4, and 6 nm, The adsorption behavior of methane on heterogeneous shale surfaces at temperatures of 298, 323, 348, 373, and 398 K and pressures of 0.1, 5, 10, 15, and 20 MPa reveals the microscopic mechanism of shale gas adsorption in organic–inorganic slit pores at a molecular scale. The results show that as temperature and pressure increase simultaneously, methane is more strongly adsorbed on the surface of graphene than kaolinite, the number of methane molecules also gradually decreases, the root mean square of the displacement of methane and different surface forces between atoms exhibit certain regularity, and the adsorption capacity of the system is proportional to the changes in diameter within the system. Van der Waals energy and electrostatic energy in the system also increase gradually with changes in temperature and pressure, and electrostatic energy has a greater influence on the adsorption of the system than van der Waal energy. These findings provide ideas for the adsorption capacity of shale gas in organic–inorganic slit pores and are critical for the accurate evaluation of shale reservoir gas content and improvement of shale gas recovery.

The Effects of Pore Wettability on the Adsorption and Flow Capacity of Shale Gas: New Insights from Molecular Dynamic Modeling

Pore wettability plays a key role in controlling shale gas adsorption and flow in marine shales. To reveal the mechanism of shale gas adsorption and flow in pores with different wettability (hydrophobic or hydrophilic), molecular modelling is simulated using the molecular dynamics method. Three pore assemblages, namely, the quartz–illite (Q–I) pores, the quartz–organic matter (Q–OM) pores, and the illite–organic matter (I–OM) pores, are proposed and the adsorption and diffusion behavior in these pores are simulated under different conditions. The results show that matrix compositions in shale greatly affect pore wettability. Water molecules preferentially absorb on the junction of materials and result in more hydrophilicity at the junction than pores. Methane density simulations reveal that free methane molecules form clusters in the Q–I pores, with higher free methane density than adsorbed methane. Methane molecules in the Q–OM pores are primarily adsorbed on organic matter. Free methane molecules extensively exist in the I–OM pores, leading stronger density of free methane than adsorbed methane. The more the proportion of free methane, the larger the methane self‐diffusion coefficient. This study provides new insights to understanding of shale gas adsorption and diffusion behavior, which is important for the effective development of shale gas reservoirs.

Water Distribution in Marine Shales: Based on Two-Dimensional Nuclear Magnetic Resonance and Low-Temperature Nitrogen Adsorption

A significant amount of foreign fluid is kept in the marine shale reservoirs after hydraulic fracturing. The water distribution characteristics in the pore space are quite complex because of the shale’s significant inhomogeneity. The change in reservoir water status brings new challenges to studying the adsorption and flow capacity of shale gas, which also brings difficulties to assessing the geological reserves of shale reservoirs and capacity prediction and development. In this study, based on a two-dimensional nuclear magnetic resonance technique and low-temperature nitrogen adsorption technique, clay minerals, organic matter, and marine shale were used as the study objects to get the distribution characteristics of water in shale pores. The results show that after entering the shale reservoir, most of the water is adsorbed on the surface of inorganic pores, mostly clay pores, to create a bound water film with a thickness of around 0.96 nm. Shale pores’ diameter, volume, and surface area are all smaller in the wet state compared to the dry, falling by 10.11, 47.02, and 71.00%, respectively. Small-scale pores (D < 10 nm) are better at absorbing water, and the water in these pores fills the spaces between them to create capillary water besides being adsorbed on the pore surface. Bound water can aid in the development of gas reservoirs and the desorption of adsorbed gas, but the capillary water column obstructs the flow of gas and restricts the flow of shale gas in microscopic pores. This study will lay a theoretical foundation for evaluating the water-bearing characteristics of marine shale reservoirs, which will help analyze the modification effect of fracturing fluid retention on reservoir water-bearing characteristics and then guide gas well development.

Quantitative Studies on the Characterization and Evaluation of Adsorbed Gas and Free Gas in Deep Shale Reservoirs

The quantitative characterization of adsorbed gas and free gas in shale reservoirs is a key issue in exploration and development of shale gas. Thus, the aforementioned topic is of great significance to the evaluation of reserves, the screening of favorable target areas, and the formulation of development plans. However, research on our current understanding of the quantities of adsorbed gas and free gas in deep shale gas reservoirs is still lacking. To address this problem, deep shales from the Longmaxi Formation in southern China were collected to conduct high-pressure isothermal adsorption experiments. The high-pressure isothermal adsorption model was used to describe the adsorption behavior of methane in deep shales, and the adsorbed gas and free gas in the deep shales were characterized quantitatively. The effects of temperature, pressure, and moisture on the adsorbed gas and the density of the free gas were analyzed. The results indicated that the excess adsorption isotherm curve for methane in deep shales increased and then decreased with the increase of pressure, and the modified Langmuir adsorption model may be used to describe the high-pressure adsorption behaviors. The adsorbed gas in shales decreases gradually with the increase of pressure, and the proportion of adsorbed gas and free gas is between 23 and 74% when the pressure reaches 50 MPa. The adsorbed gas in deep shales decreases with an increase of temperature, and the presence of water greatly reduces the adsorption capacity of the deep shale. The pore space occupied by the free gas in shale increased with the increase in the density of the free phase, and the ratio of the adsorbed gas to the free gas decreased. This research provides a useful reference for explaining how to best evaluate shale gas reservoirs, estimate the reserves in deep shales, and evaluate the adsorption and flow capacity of deep shale gas.

Molecular simulation calculation method for shale gas adsorption in realistic shale model

An accurate evaluation of the adsorption capacity of shale formations relies on a quantitative determination of the capacity for shale gas adsorption. However, the molecular simulations at the microscopic scale performed by most research institutes do not provide an accurate reflection of the results of macroscopic experiments. In addition, due to the multi-scale pore structure and non-uniform rock composition, the adsorption micro-mechanisms of shale reservoirs are complex and diverse, and related theories still need to be studied and perfected. This research used X-ray diffraction and total organic carbon experimental data to propose a shale molecular model based on data from actual shale formations. The proposed model considers mineral and organic contents, mineral cell structures, lattice parameters, mineral arrangements, and pore diameters, and it corresponds well to actual shale formations. Under temperature and pressure conditions of the shale formation, the established shale molecular model corresponds more closely to actual formation conditions in terms of shale gas adsorption capacity and specific surface area than previous single-mineral models. At the same time, the variation between the adsorption simulation result obtained from the shale molecular model and the result from the adsorption experiment was less than 5%. This further confirms the authenticity and reliability of the constructed shale molecular model. On the basis of shale molecular model, deep shale gas adsorption data at pressures above 30 MPa were predicted. It's show that the adsorption capacity of shale gas approaches the saturated adsorption capacity when the shale formation pressure reaches 75 MPa.

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.

Pore changes of slickwater-containing shale under supercritical CO2 treatment

Application of liquid CO2-slickwater hybrid fracturing technology can significantly improve the energy-enhancing efficiency and fracturing fluid flowback efficiency of shale reservoirs. However, supercritical CO2 (ScCO2) fluid and slickwater are inevitably retained in reservoirs after fracturing, resulting in limited understanding of the changes of shale pore structure, further impacting the evaluation of the gas adsorption and transportation behaviors as well as CO2 sequestration capacity in shale reservoirs. Therefore, the influences of the ScCO2-slickwater coupling effect on shale pore structure was analyzed by using X-ray diffraction, low-pressure nitrogen gas adsorption (N2GA), mercury intrusion porosimetry (MIP), field emission-scanning electron microscopy (FE-SEM), and fractal analysis. After ScCO2-slickwater treatment, the calcite and albite contents decreased, while the quartz and clay minerals contents increased in shale. The increase in number of micropores and mesopores and the reduction in number of macropores were observed by a combination of N2GA and MIP, which led to the total specific surface area (TSSA) and total pore volume (TPV) of the shale enlarged, while the average pore size reduced. Meanwhile, the fractal dimensions calculated by N2GA (D1, D2) and MIP (D3) were raised, indicating that pore surface roughness and structural complexity were strengthened. D1, D2 and D3 can roughly reflect fractal characteristic of micropores (<3.5 nm), mesopores (3.5–50 nm) and macropores (>50 nm), respectively. Thus, D1 and D2/D3 can be used to evaluate the gas adsorption and flow behaviors of shale, respectively. By analyzing the control experimental results of ScCO2-water and He-slickwater treatment and the FE-SEM images, shale pore changes after ScCO2-slickwater treatment can be explained by CO2 extraction and dissolution, secondary mineral precipitation and polyacrylamide adsorption. After treatment, the increase of micropores and mesopores as well as TSSA and TPV makes the gas-adsorption capacity of shale improved, showing that the coupling effect of ScCO2-slickwater can not only improve shale gas productivity, but also benefit geological storage of CO2.

Gas adsorption characteristics in deep marine shale gas reservoirs based on molecular simulation

It is of great significance to clarify the adsorption law of shale gas under in-situ conditions for the development of deep marine shale gas reservoirs. However, temperature and pressure in deep reservoirs are far higher than those in the range of normal experiments, so the adsorption characteristics of shale gas in the high-pressure section have not been revealed. In this paper, we construct a kerogen model which conforms to the adsorption law of real marine shale samples by using molecular simulation technology, and simulate the methane adsorption at high temperature and high pressure (HTHP) under in-situ conditions. The adsorption characteristics of methane at HTHP under the influence of primary water are comprehensively revealed, and a corresponding reliable isothermal adsorption model is established. The results show that the influence of kerogen molecular number must be fully considered in the construction of kerogen model, otherwise large errors will occur. The shale gas adsorption capacity is stable under the influence of temperature and changes more significantly with the pressure. In kerogen with polar functional group water can significantly reduce methane adsorption, especially under high pressure. The research results can provide a theoretical basis for the adsorption gas evaluation for deep marine shale gas reservoirs.

Effect of Pre-Adsorbed Water on Methane Adsorption Capacity in Shale-Gas Systems

The presence and content of water will certainly affect the gas adsorption capacity of shale and the evaluation of shale gas content. In order to reasonably evaluate the gas adsorption capacity of shale under actual reservoir conditions, the effect of water on methane adsorption capacity needs to be investigated. Taking the Da’anzhai Member of the Lower Jurassic Ziliujing Formation in the northeastern Sichuan Basin, China as an example, this study attempts to reveal the effect of pre-adsorbed water on methane adsorption capacity in shale-gas systems by conducting methane adsorption experiments in two sequences, firstly at different temperatures under dry condition and secondly at different relative humidity levels under the same temperature. The results show that temperature and relative humidity (i.e., water saturation) are the main factors affecting the methane adsorption capacity of shale for a single sample. The key findings of this study include: 1) Methane adsorption capacity of shale first increases then decreases with depth, reaching a peak at about 1,600–2,400 m. 2) Lower relative humidity correlates to greater maximum methane adsorption capacity and greater depth to reach the maximum methane adsorption capacity. 3) 20% increase of relative humidity results in roughly 10% reduction of maximum methane adsorption capacity. As a conclusion, methane adsorption capacity of shale is predominately affected by water saturation, pore type and pore size of shale. This study could provide a theoretical basis for the establishment of a reasonable evaluation method for shale adsorbed gas content.

Critical factors controlling adsorption capacity of shale gas in Wufeng-Longmaxi formation, Sichuan Basin: Evidences from both experiments and molecular simulations

The quantitative determination of the influence of the critical factors on the adsorption capacity of the shale is important for accurately evaluating its adsorption capacity under the geological conditions. The adsorption experiments are performed on both the dry and the water-saturated shale samples, and the Grand Canonical Monte Carlo (GCMC) simulations are carried out on both the organic and inorganic structures. It is found that the organic matters (OM), with strong intensity and high distribution density of the adsorption sites and large specific surface area, are the most important adsorbent in the shale, accounting for 53%~92% of the adsorption capacity, and the clay minerals take the second place. For most of the adsorption sites on the clay minerals, the adsorption capacity will be impeded by the formation water because of their hydrophilicity, while only the adsorption capacity of the polar group (with hydrophilicity) on the organic surface will be hindered by the formation water. For the shale in the study area, the TOC increases with the depth, causing the increasing of the adsorption amount under the geological conditions, at the same time, the clay mineral content decreases with the depth, causing the descent of the impede effect of the formation water. The quantitative investigation of the influence of the critical factors on the adsorption behaviors of the shale gas is hopeful to provide some helpful insights and references when evaluating the adsorption amount of shale gas under the geological conditions.

CH₄ and CO₂ Adsorption Mechanism in Kaolinite Slit Nanopores as Studied by the Grand Canonical Monte Carlo Method.

To confirm the rules and transformation conditions of shale gas adsorption and establish a model for evaluating the adsorption capacity of shale gas quantitatively, it is necessary to reveal the shale gas adsorption mechanism. The adsorption mechanism of CH₄ and CO₂ in Kaolinite slit nanopores has been studied under the simulated conditions of 90 °C and 30 or 50 MPa by the grand canonical Monte Carlo (GCMC) method. The results indicate that CH₄ is controlled only by the Van der Waals forces on the mineral surface because CH₄ is nonpolar, while CO₂ is controlled by both Van der Waals forces and Coulomb forces due to a certain electric quadrupole moment, which makes the adsorption capacity of CO₂ on kaolinite greater than that of CH₄. Due to the overlapping adsorption potential on the kaolinite surface of micropores (1 nm), the peak of the density profile is higher in the micropores than the peak in the mesopores (4 nm), resulting in the filling effect in the micropores. On the surface of the silicon-oxygen octahedron, the adsorption site for CH₄ and CO₂ is in the center of the silicone hexagon-ring, and CO₂ with a quadrupole moment shifts near the polar oxygen atoms. In contrast, the adsorption sites of CH₄ are relatively dispersed on the surface of the aluminum-oxygen octahedron with a hydroxyl group, while the adsorption sites of CO₂ are concentrated in the location of the aggregated oxygen atoms. When CH₄ and CO₂ coexist, CO₂ tends to be adsorbed prior to CH₄. With the proportion of CO₂ increasing, the competitive adsorption effect is gradually aggravated, which suggests the rationality of injecting CO₂ to improve the recovery efficiency of shale gas. These findings can provide theoretical support for shale gas exploration and development.

A novel experimental system for accurate gas sorption and its application to various shale rocks

Accurate measurement of shale gas adsorption capacity is crucial for reservoir appraisal and production stimulation. Because of the limited adsorption capacity and finer pore size distribution in shale matrix, it is difficult to precisely quantify the adsorption capacity using traditional volumetric methods for coal adsorption measurement. An improved lab method for shale adsorption measurement and diffusivity evaluation was introduced by using a control group connected through a high accuracy differential pressure transducer. Isotherm curves of five shale samples from different basins were acquired using this system. For all shale samples, adsorption capacity for CO2 is 2–3 times of that for CH4. Adsorption isotherms for shale exhibited a better fitting trend with the BET model at the pressure range of lab scale, indicative of the quick decline at the diffusion-dominant region of reservoir production curve. It is found that the improved adsorption measurement method can effectively reduce the average accumulated error from 24.3%–11.3%, and it is qualified for measurement of materials with limited adsorption capacity.

Pore size distributions contributed by OM, clay and other minerals in over-mature marine shale: A case study of the Longmaxi shale from Southeast Chongqing, China

Nano-scale pores play an important role in determining the adsorption capacity of shale gas. To quantitatively evaluate the pore size distributions contributed by organic matter (OM), clay and other minerals in an over-mature shale reservoir, the Lower Silurian Longmaxi shale from Southeast Chongqing was selected as a case study and was analyzed by the pore size distributions contributed by OM, clay and other minerals (PSDCOCO) method. Based on the results of total organic carbon (TOC), carbon element content in OM, X-ray diffraction (XRD) and low temperature nitrogen adsorption/desorption (LTNA) experiments, the pore size distributions contributed by a unit mass of OM, clay and other minerals were calculated and the differences between the results of the LTNA and PSDCOCO methods were determined for the four verified samples. The average value of the difference between the experimental and calculated pore volumes is 0.154 × 10−3 cm3/g. For the Longmaxi shale from the Py1 well, the contributions of OM and other minerals to the pore volume (pore width <200 nm) are primarily distributed in the pore width ranges from 2 to 20 nm and <2 nm, respectively. The nano-scale pore size distributions (<200 nm) contributed by the clay minerals have two relatively high peak values in the pore width ranges of 20–100 nm and 2–5 nm. The pore volumes for pore widths less than 200 nm contributed by a unit mass of OM, clay and other minerals were 115.776 × 10−3 cm3/g, 10.489 × 10−3 cm3/g and 0.006 × 10−3 cm3/g, respectively. In the shale reservoir, the contributions of OM, clay and other minerals to the pore volume with pore widths less than 200 nm were 45.75%, 54.17% and 0.08%, respectively, based on the limited data available.

Investigation of variation in shale gas adsorption capacity with burial depth: Insights from the adsorption potential theory

In this study, the Polanyi theory was applied to investigate variation in shale gas adsorption capacity with burial depth. Analyses were implemented on background data of two shale samples with respective TOC contents of 4.00% and 4.51% TOC, accompanied by combination of the Polanyi theory and isothermal adsorption parameters. Shale gas adsorption capacity was found to first increase and then decrease as the burial depth grew, and the burial depth corresponding to the maximum adsorption capacity was basically constant within the study area. Specifically, pressure coefficient had the largest impact on the minimum adsorption potential, reaching 1.721 mol/kJ, while the ground temperature gradient was the most influential factor on the burial depth corresponding to the maximum adsorption capacity, reaching 1080 m. When the burial depth was shallower than 3200 m, the pressure coefficient dominated, whereas in deeper parts, the ground temperature gradient became dominant.

Influencing Factors of Gas Adsorption Capacity of Marine Organic Shale: A Case Study of Dingshan Area, Southeast Sichuan

Xie, J.; Qin, Q., and Fan, C., 2019. Influencing factors of gas adsorption capacity of marine organic shale: A case study of Dingshan Area, Southeast Sichuan. In: Guido-Aldana, P.A. and Mulahasan, S. (eds.), Advances in Water Resources and Exploration. Journal of Coastal Research, Special Issue No. 93, pp. 507–511. Coconut Creek (Florida), ISSN 0749-0208.The gas bearing property of marine shale is very important to the reserve calculation of shale gas field, which is directly related to the productivity and decline law of shale gas. The development of coastal shale gas is also the reserve field of shale gas exploration at present. Based on the conventional marine shale, this study adopts cylindrical shale core to measure the adsorption gas volume by testing the gas volume change in the process of pressure reduction and desorption of marine shale gas, simulates the conditions of different temperature, pressure, water cut, real pore structure and so on, and eliminates the negative adsorption anomaly of isotherm adsorption curve. The effects of organic matter content, pressure, temperature, water content and gas composition on the adsorption capacity of marine shale were analyzed. The experimental results show that the pressure condition controls the desorption process of shale gas, and the increase of pressure suppresses the desorption of shale gas. Within a certain range, with the increase of pressure, the adsorption gas volume of marine shale also increases. A large number of micropores of organic matter are developed, which greatly increases the specific surface area of organic matter. Under certain maturity conditions, with the increase of organic matter content, the adsorption volume of shale increases. The increase of temperature increases the activation energy of molecular surface and accelerates the desorption process of shale gas. When the shale is water-bearing, the water molecules occupy the active adsorption site on the shale mineral surface, which reduces the shale gas adsorption capacity. The research results have certain theoretical guidance for the exploration and development of coastal shale gas in the next stage.

Interaction of shale gas recovery and moisture transport in post two-phase flowback stage

In the post two-phase flowback stage of shale gas recovery, the residual water in fractures no longer forms a stable continuous flow but mitigates through moisture transport. How this residual water affects gas production is still not clear. This paper studies the motion of this residual water during shale gas recovery. Following three aspects are mainly studied: First, the residual water forms a water film on the surface of fractures and makes Darcy flow in fractures no longer applicable. A new empirical formula for threshold pressure gradient is proposed and directly related to residual water saturation. Second, moisture transports through diffusion, convection and evaporation reaction. Especially, the evaporation of water film depends on surrounding humidity, water activity, and gas flow rate. This evolution of water film is a dynamic equilibrium process and impacts fracture permeability. Third, residual water in matrix interacts with clay minerals to form bonded water. This part of water modifies the Langmuir isotherm adsorption and changes the adsorption capacity of shale gas. Thus the moisture transport significantly affects the shale gas recovery, which should be carefully considered.

Study of CH4 and CO2 competitive adsorption on shale in Yibin, Sichuan Province of China

Shale gas is an unconventional gas source with substantial development potential. In this study, Longmaxi Formation shale from the Silurian system in Yibin, Sichuan Province was collected for characterizing total organic carbon (TOC), clay mineral content, and other reservoir properties. The pore structure of shale was analyzed by field-emission scanning electron microscopy and low-temperature N2 adsorption–desorption method. Isothermal adsorption experiments for CH4 and CO2 mixtures in shale samples were performed. The second Virial coefficient was used to calculate for the compressibility factor of the gas mixture. The influencing factors of gas adsorption capacity of shale were analyzed. Finally, the CH4 and CO2 adsorption capacities and selection of shale samples were investigated. Under low pressure, the total gas mixture capacity of shale samples was positively correlated with pressure. When the pressure increased to a certain extent, the growth trend of gas mixture adsorption capacity of shale samples decreased. The mixed gas adsorption volume is high at 50 °C for all the proportion. Given the same temperature and pressure, the CO2 adsorption of shale samples is higher than the CH4 adsorption. In competitive adsorption, shale prefers to adsorb CO2. Therefore, CO2 is easier to be adsorbed by shale and this causes CH4 to be released from the adsorption site.

Ono-Kondo lattice model for propane multilayer adsorption in organic nanopores in relation to shale gas

Accurate characterization of shale gas adsorption capacity is of great importance to the gas-in-place estimation and prediction of well productivity. Propane is one of major constituents in shale gases which can have multilayer adsorption behavior on pore surfaces. While experiments can measure excess adsorption, the absolute adsorption, which describes adsorbed gas capacity, has to be converted from the excess adsorption. In previous works, absolute adsorption is usually calculated from excess adsorption with adsorbed phase volume or density based on the single-layer adsorption model. However, for heavier alkanes, such as ethane and propane, which can have multilayer adsorption behavior, single-layer adsorption model becomes invalid. While molecular simulation can characterize the multilayer adsorption behavior, it comes with expensive computational costs. Currently, there is no viable model to characterize the absolute adsorption of hydrocarbons which can have multilayer adsorption behavior. In this work, we conduct grand canonical Monte Carlo (GCMC) simulation to study propane adsorption in shale nanopores over a wide range of pressures at temperature higher than the critical temperature. We find that propane can form multiple adsorption layers, thus, using single-layer adsorption model to obtain the absolute adsorption becomes unjustifiable. Based on the propane density distribution characteristics, we propose a multilayer adsorption model and use Ono-Kondo (OK) lattice model with multilayer structures to regress propane excess adsorption and subsequently obtain the absolute adsorption in each layer. For propane, we take into account the correlation effect arising from strong adsorbate–adsorbate interactions beyond mean field theory (MFT) and the only predetermined parameters are number of layers and adsorption layer width. The proposed OK model shows an excellent agreement with GCMC simulations on the excess adsorption and absolute adsorption in each layer, with discrepancies less than 6% above 50 bar. The proposed OK model can readily take into account the propane multilayer adsorption behavior, while significantly reducing calculation time. Our method presents a reliable and highly-efficient approach for accurate characterization of adsorption of hydrocarbons with multilayer structures and provide important insights into the gas-in-place estimation in shale.