Search

Summary Due to intermolecular interactions, the oil/water two-phase flow behaviors in shale nanoporous media are complex and diverse, which cannot be characterized by a conventional continuum flow equation. In this work, we propose a nanoscale multirelaxation-time multicomponent and multiphase lattice Boltzmann method (MRT-MCMP-LBM) based on pseudopotential format to simulate oil/water two-phase flow at the pore scale. The nanoscale effect of liquid/solid slip, liquid/liquid slip, and heterogeneous viscosity due to liquid/solid and liquid/liquid molecular interactions is fully taken into account. We use the Laplace test, contact angle, and phase separation to calibrate the desired interfacial tension (IFT) and wettability. Then, the proposed model is verified by comparing to molecular simulation and theoretical results. Although the liquid/solid slip can increase the oil/water flow capacity, it can reduce the relative permeability due to the increased intrinsic permeability. The oil/water interfacial slip can increase the relative permeability of the nonwetting phase, which can be greater than unity because the effect of oil/water interfacial slip is greater than that of nonwetting-phase/wall slip. We also calibrate the microscopic parameters of oil and water flow in inorganic and organic pores by comparing their velocity profiles to those from molecular dynamics (MD) simulations. The oil/water two-phase flow in shale nanoporous media indicates that with a higher total organic carbon (TOC) content, oil relative permeability is lower due to the more significant adverse nanoscale effect. The proposed model can be potentially applied to simulate shale oil/gas/water multicomponent and multiphase (MCMP) flow, imbibition, CO2 huff ‘n’ puff, and geological sequestration.

Divalent ions, which are omnipresent in brine, may be detrimental to surfactant functionalities during chemical flooding in the enhanced oil recovery (EOR) process. Surfactant blending is one potential solution to overcome such an adverse effect. Herein, we report a molecular dynamics (MD) study to investigate the molecular arrangement and possible applications of surfactant blending in hard water-resistant chemical flooding for oil recovery. We chose commonly used anionic surfactants, sodium dodecyl sulfate (SDS), as primary surfactants. The non-ionic (propanol) and cationic [cetrimonium bromide (CTAB)] surfactants with a wide range of concentrations are introduced to the primary system. We demonstrate that CTAB can disaggregate the cation bridging when their concentration is above a certain threshold. This threshold value is related to the surfactant and cosurfactant surface charge in the interface region. The cation bridging density is maintained at a low level when the sum of surfactants and cosurfactant interface charges is neutral or positive. On the other hand, propanol barely disaggregates the cation bridging. When propanol concentration is above a certain value, it even facilitates the cation bridging formation. Both propanol and CTAB can further decrease the oil-brine interfacial tension (IFT) while having different efficacies (IFT decrement rate is different as their interface concentration increases). More rapid IFT decrement is observed when cation bridging is disaggregated (

Highly active and durable electrocatalysts towards oxygen reduction reaction (ORR) are imperative for the commercialization application of proton exchange membrane fuel cells. By manipulating ligand effect, structural control, and strain effect, we report here the precise preparation of Mo-doped Pt3Co alloy nanowires (Pt3Co-Mo NWs) as the efficient catalyst towards ORR with high specific activity (0.596 mA cm−2) and mass activity (MA, 0.84 A mg−1Pt), much higher than those of undoped counterparts. Besides activity, Pt3Co-Mo NWs also demonstrate excellent structural stability and cyclic durability even after 50,000 cycles, again surpassing control samples without Mo dopants. According to the strain maps and DFT calculations, Mo dopants could modify the electronic structure of both Pt and Co to achieve not only optimized oxygen-intermediate binding energy on the interface but also increased the vacancy formation energy of Co, together leading to enhanced activity and durability. This work provides not only a facile methodology but also an in-depth investigation of the relationship between structure and properties to provide general guidance for future design and optimization.

Despite a great promise in the enhanced oil recovery in tight formations, CO2 flooding with surfactants is hindered due to the low surfactant solubility in supercritical CO2 (scCO2). Alcohol blending can increase the sodium bis(2-ethylhexyl) sulfosuccinate (AOT) solubility in scCO2. While this finding offers a promising solution to CO2 flooding in tight oil reservoirs, to the best of our knowledge, their working mechanism still remains elusive. Herein, we report a molecular dynamics simulation study to explore the working mechanism of alcohols in reverse micelle (RM) dispersity ("solubility") increment. The spontaneous aggregation process in two systems (System A consisting of AOT and scCO2; System B consisting of AOT, scCO2, and 10 wt % ethanol) are conducted under a typical tight oil reservoir condition (333 K and 200 bar). After 600 ns runs, the AOT molecules aggregate together and form rod-like RMs in System A, while form several small sphere-like RMs in System B. We observe that the aggregation process in System A occurs when two clusters approach each other end-to-end. More CO2 molecules are around the Na+ ion at the end of the clusters, which can be readily replaced by AOT molecules. On the other hand, the ethanol molecules can better solvate and surround Na+ ions, preventing the further aggregation of AOT clusters in System B. The potential of mean force calculations also reveal that while two small clusters formed by four AOT molecules attract each other in System A, they repel each other in System B. Our work should provide important insights into the design of scCO2-soluble surfactant formulas.

Recent research revealed inhibition or enhancement of dissolved organic matter (DOM) to the degradation of trace organic contaminants (TrOC) in natural and engineered water systems. Phenols containing acetyl, carboxyl, formyl, hydroxy, and methoxy groups were selected as the model DOM to quantitatively study their roles in the degradation of simple anilines, sulfonamide antibiotics, phenylurea pesticides by sulfate radicals (SO

As one common unconventional reservoir, shale plays a pivotal role to compensate the depletion of conventional oil resources. There are numerous nanoscale pores and ultra-narrow pore throats (sub 2 nm) in shale media. To displace oil through ultra-narrow pore throats by water, one needs to overcome excessively-high capillary pressure. Understanding the water-oil two-phase displacement process through pore throats is critical to numerical simulation on tight/shale oil exploitation and ultimate oil recovery estimation. In this work, we use molecular dynamics simulations to investigate oil (represented by

The lithium-sulfur (Li-S) battery is regarded as a promising secondary battery. However, constant parasitic reactions between the Li anode and soluble polysulfide (PS) intermediates significantly deteriorate the working Li anode. The rational design to inhibit the parasitic reactions is plagued by the inability to understand and regulate the electrolyte structure of PSs. Herein, the electrolyte structure of PSs with anti-reductive solvent shells was unveiled by molecular dynamics simulations and nuclear magnetic resonance. The reduction resistance of the solvent shell is proven to be a key reason for the decreased reactivity of PSs towards Li. With isopropyl ether (DIPE) as a cosolvent, DIPE molecules tend to distribute in the outer solvent shell due to poor solvating power. Furthermore, DIPE is more stable than conventional ether solvents against Li metal. The reactivity of PSs is suppressed by encapsulating PSs into anti-reductive solvent shells. Consequently, the cycling performance of working Li-S batteries was significantly improved and a pouch cell of 300 Wh kg-1 was demonstrated. The fundamental understanding in this work provides an unprecedented ground to understand the electrolyte structure of PSs and the rational electrolyte design in Li-S batteries.

Summary Two-phase and three-phase equilibria are frequently encountered in a variety of industrial processes, such as carbon dioxide (CO2) injection for enhanced oil recovery in oil reservoirs, multiphase separation in surface separators, and multiphase flow in wellbores and pipelines. Simulation and engineering design of these processes using isothermal/isochoric (VT) multiphase equilibrium algorithms are sometimes more convenient than that using the conventional isothermal/isobaric (PT) algorithms. This work develops a robust algorithm for VT multiphase equilibrium calculations using a nested approach. The proposed algorithm is simple because a robust PT multiphase equilibrium algorithm is used in the inner loop without any further modifications, while an effective equation-solving method (i.e., Brent’s method; Brent 1971) is applied in the outer loop to solve the pressure corresponding to a given volume/temperature specification. The robustness of the VT algorithm is safeguarded by using a highly efficient trust-region-method-based PT algorithm. We demonstrate the good performance of the newly developed algorithm by applying it to calculate the isochores of fluid mixtures that exhibit both two-phase and three-phaseequilibria.

Shale/tight gas plays an increasingly important role to meet the growing global energy demand and reduce carbon emissions. Unlike conventional reservoirs, shale formations are subject to rock heter...

The aggregation behavior of carboxymethyl chitosan (CMCS) plays an important role in its extensive applications. Here, we perform molecular dynamics simulations to investigate aggregation behaviors of CMCS in water and the effects of degrees of deacetylation (DD) and substitution (DS) and ionization states (equivalently different pH conditions). CMCS prefers to aggregate in neutral condition, self-assembling into multimeric forms with interlaced stacking of molecular chains, while forming dimer or trimer through twisted stacking and parallel stacking in acidic and alkaline conditions, respectively. With the increase of DD and DS, the aggregation becomes weaker when in neutral and alkaline conditions, while gets stronger in acidic environment. The presence of intramolecular hydrogen bonds and exo-anomeric effect causes twisted, coplanar and extended conformations of individual chain in acidic, alkaline and neutral conditions, respectively, contributing to their distinct inter-chain stacking structures. Subsequently, the specific intermolecular hydrogen bonding, hydrophobic and electrostatic interactions stabilize the aggregation structures.

CO2 sequestration in shale reservoirs is an economically viable option to alleviate carbon emission. Kerogen, a major component in the organic matter in shale, is associated with a large number of nanopores, which might be filled with water. However, the CO2 storage mechanism and capacity in water-filled kerogen nanopores are poorly understood. Therefore, in this work, we use molecular dynamics simulation to study the effects of kerogen maturity and pore size on CO2 storage mechanism and capacity in water-filled kerogen nanopores. Type II kerogen with different degrees of maturity (II-A, II-B, II-C, and II-D) is chosen, and three pore sizes (1, 2, and 4 nm) are designed. The results show that CO2 storage mechanisms are different in the 1 nm pore and the larger ones. In 1 nm kerogen pores, water is completely displaced by CO2 due to the strong interactions between kerogen and CO2 as well as among CO2. CO2 storage capacity in 1 nm pores can be up to 1.5 times its bulk phase in a given volume. On the other hand, in 2 and 4 nm pores, while CO2 is dissolved in the middle of the pore (away from the kerogen surface), in the vicinity of the kerogen surface, CO2 can form nano-sized clusters. These CO2 clusters would enhance the overall CO2 storage capacity in the nanopores, while the enhancement becomes less significant as pore size increases. Kerogen maturity has minor influences on CO2 storage capacity. Type II-A (immature) kerogen has the lowest storage capacity because of its high heteroatom surface density, which can form hydrogen bonds with water and reduce the available CO2 storage space. The other three kerogens are comparable in terms of CO2 storage capacity. This work should shed some light on CO2 storage evaluation in shale reservoirs.

Accurate estimation of CH4 absolute adsorption amount is essential for shale gas-in-place (GIP) evaluation as well as well productivity. Recent studies have shown that pore size distribution (PSD) ...

Concerns over the environmental impacts of thermal production methods for bitumen and heavy oil have led to the exploration of alternative technologies including solvent-assisted production methods...

A cosurfactant is a chemical used in combination with a surfactant to enrich the properties of the primary surfactant formulation. Understanding the roles of a cosurfactant is of great importance in designing a chemical solution with desired features. Herein, we report a molecular dynamics simulation study to explore the roles of alcohol (propanol) as a cosurfactant at a brine-oil interface in chemical flooding under a typical reservoir condition (353 K and 200 bar). We demonstrate that propanol, as a cosurfactant, can be transported through oil and brine phases; such a dislocation of propanol in the system is a dynamic process. The interfacial tension between brine and oil decreases as propanol concentration in the system increases. This is because propanol can form hydrogen bonds with water molecules while it decreases the density of hydrogen bonds formed between the surfactant and water. The introduction of propanol does not always increase the local fluidity of surfactants at the interfaces. A local maximum fluidity was observed when the surfactants are more perpendicular to the interfaces. Our work should provide important insights into the design of the surfactant formulas for chemical flooding during enhanced oil recovery.

Surface wettability regulation plays a crucial role in antifouling and related applications. For regulating surface wettability, one of the effective approaches is to modulate the surface charge distribution. Herein, we report a theoretical study for unraveling the mechanistic relation between surface charge distribution and ionic substrate wettability. Specifically, acetonitrile liquids at ambient condition in contact with various ionic substrates are considered. At different surface charge distributions, the interfacial thermodynamic properties are investigated by means of molecular density functional theory. We find that the variation of the spatial interval among the discrete charges strongly alters the substrate-acetonitrile interaction and leads to an oscillation in the interfacial tension, indicating that the substrate can be tuned from a solvophobic one to a solvophilic one. This trend can be further enhanced by increasing the charge quantity. The underlying mechanisms are extensively discussed and expatiated. Our work provides theoretical guidance to engineer and regulate surface wettability.

Summary Hydrocarbon recovery from shale subformations has greatly contributed to the global energy supply and has been constantly reshaping the energy sector. Oil production from shale is a complex process in which multicomponent–fluid mixtures experience multiphase transitions in multiscale volumes (i.e., nanoscale pores are connected to fractures/macropores). Understanding such complicated phenomena plays a critical role in the estimation of ultimate oil recovery, well productivity, and reserves estimation, and ultimately in policy making. In this work, we use density–functional theory (DFT) to explicitly consider fluid/surface interactions, inhomogeneous–density distributions in nanopores, volume partitioning in nanopores, and connected macropores/natural fractures to study the complex multiphase transitions of multicomponent fluids in multiscale volumes. We found that vapor–like and liquid–like phases can coexist in nanopores when pressure is between the bubblepoint and dewpoint pressures of nanoconfined fluids, both of which are much lower than those of the originally injected hydrocarbon mixtures. As the volume ratio of the bulk at the initial condition to pores decreases, both the bubblepoint and the dewpoint in nanopores increase and the pore two–phase region expands. Within the pore two–phase region, both C1 and C3 are released from the nanopores to the bulk phase as pressure declines. Meanwhile, both liquid and vapor phases become denser as pressure drops. By further decreasing pressure below the dewpoint of confined fluids, C3 in the nanopore can be recovered. Throughout the process, the bulk–phase composition varies, which is in line with the field observation. Collectively, this work captures the coupled complexity of multicomponent and multiphase fluids in multiscale geometries that is inherent to shale reservoirs and provides a theoretical foundation for reservoir simulation, which is significant for the accurate prediction of well productivity and ultimate oil recovery in shale reservoirs.

Salt ion valency and concentration vary in actual oil reservoirs, which play an important role in the functionalities of surfactant formula during chemical flooding processes to enhance oil recovery. Herein, we report a molecular dynamics (MD) study to investigate the ion valency and concentration effect on the structural and thermodynamic properties of brine-decane interfaces with anionic surfactant (SDS), under typical reservoir conditions (353 K and 200 bar). We use two different cations (Na+ and Ca2+) and a wide range of ion concentrations (up to 3.96 M) to simulate reservoir conditions. We find that ion valency has a significant effect on the molecular configurations, which further influences the thermodynamic properties. Ca2+ ions can have a strong adsorption at the interface due to the strong electrostatic interactions between Ca2+ ions and SDS, which also results in the Cl- ion enrichment at the interface. Furthermore, Ca2+ ions can form pentagon-like SDS-Ca2+ complexes through SDS-Ca2+-SDS cation bridging, which renders a nonuniform distribution of SDS at the interface. On the other hand, the cation bridging density monotonically increases as ion concentration increases for the systems without Ca2+ ions, while first increases, then decreases for the systems with Ca2+ ions. This is because the accumulation of Cl- ions at the interface at high salt concentrations can melt SDS-Ca2+ complexes. This work should provide new insights into the structural and thermodynamic properties of brine-oil interfaces with an anionic surfactant, which can facilitate the optimization of chemical flooding processes.

Despite a great promise in the enhanced oil recovery in tight formations, CO

Oil–brine interfaces play an important role in oil recovery and oil–brine separation, in which the effects of salinity on interfacial tension (IFT) have been much of debate in the past in experiments and modeling studies owing to complex oil compositions. In this work, we use molecular dynamics (MD) simulations to study the oil–brine interfacial properties by designing seven systems containing different oil compositions (decane with/without polar compounds) and the salinity in brine of up to ∼14 wt %. We carefully investigate the salinity and polar component effects by analyzing IFTs, density profiles, orientation parameters, hydrogen bond densities, and charge density profiles. The results indicate that O-bearing compounds (phenol and decanoic acid) can significantly reduce the oil–brine IFT and exhibit the highest Gibbs surface excess relative to water, while the others, including N-bearing compounds (pyridine and quinoline) and S-bearing compounds (thiophene and benzothiophene), only slightly decrease ...

CO2 sequestration and enhanced gas recovery (CS-EGR) is a viable option with enormous potentials to produce shale gas. However, the microscopic competitive sorption behaviors of CH4 and CO2 in vari...

It is crucial to accurately characterize methane absolute adsorption in kerogen nanoporous media for gas-in-place evaluation and well productivity prediction. Assuming that methane forms a single-l...

Enhanced recovery of shale gas with CO2 injection has attracted extensive attention as it combines the advantages of improved efficiency of shale gas recovery and reduced greenhouse gas emissions via CO2 geological sequestration. On the other hand, the microscopic mechanism of enhanced shale gas recovery with CO2 injection and the influence of the subsurface water confined in the shale nanopores remain ambiguous. Here, we use grand canonical Monte Carlo (GCMC) simulations to investigate the effect of moisture on the shale gas recovery and CO2 sequestration by calculating the adsorption of CH4 and CO2 in dry and moist kerogen slit pores. Simulation results indicate that water accumulates in the form of clusters in the middle of the kerogen slit pore. Formation of water clusters in kerogen slit pores reduces pore filling by methane molecules, resulting in a decrease in the methane sorption capacity. For the sorption of CH4/CO2 binary mixtures in kerogen slit pores, the CH4 sorption capacity decreases as the moisture content increases, whereas the effect of moisture on CO2 sorption capacity is related to its mole fraction in the CH4/CO2 binary mixture. Furthermore, we propose a reference route for shale gas recovery and find that the pressure drawdown and CO2 injection exhibit different mechanisms for gas recovery. Pressure drawdown mainly extracts the CH4 molecules distributed in the middle of kerogen slit pores, while CO2 injection recovers CH4 molecules from the adsorption layer. When the water content increases, the recovery ratio of the pressure drawdown declines, while that of CO2 injection increases, especially in the first stage of CO2 injection. The CO2 sequestration efficiency is higher under higher water content. These findings provide the theoretical foundation for optimization of the shale gas recovery process, as well as effective CO2 sequestration in depleted gas reservoirs.

In this work, we develop an alternative two-phase flash algorithm with the consideration of capillary pressure at specified mole numbers, volume, and temperature. This algorithm is built upon the volume-temperature (VT) two-phase flash algorithm as proposed by Mikyska and Firoozabadi (2012), which relies on the use of the newly defined volume function and volume function coefficient. Our algorithm contains two loops: an inner loop and an outer loop. In the inner loop, the interior point method is used to solve the vapor-phase fraction by minimizing the objective function. In the outer loop, the volume fraction of the vapor phase is updated by solving the pressure equilibrium equation which simultaneously considers the capillary pressure between the two phases; herein, we first divide the interval (0, 1) to 1000 subintervals and then apply the bisection method in each subinterval. This method is used to robustly solve the pressure equilibrium equation. The capillary pressure is calculated using the Young-Laplace equation on the basis of the interfacial tension predicted by the parachor model. Eventually, knowing the volume fractions enables one to update the equilibrium ratios in the outer loop. We demonstrate the correctness and robustness of our algorithm by testing it against four fluid mixtures, including binary and ternary mixtures. The two-phase envelope obtained from the VT-flash algorithm with capillarity effect has shown excellent agreement with that calculated by the pressure-temperature (PT) flash algorithm with capillarity effect. In addition, we examine the influence of capillary pressure on the two-phase envelope in the molar-density/temperature (cT) space.

Accurate characterization of methane absolute adsorption in shale nanoporous media is of great importance to the gas-in-place (GIP) estimation and well productivity. Because experimental measurement can only provide the excess adsorption, the absolute adsorption is generally converted from the excess adsorption based on the single-layer adsorption model. However, it is well known that shale has a widespread pore size distribution (PSD), ranging from sub 2-nm to hundreds of nanometers. In micropores ( Based on the varying density profiles in different nanopores obtained from GCMC, we propose the corresponding methane adsorption model in each nanopore, which is applied in Ono-Kondo (OK) lattice model. By fitting the excess adsorption in nanoporous media and explicitly considering the PSD, OK model can readily obtain the absolute adsorption. In order to validate our model, 1000 sets of randomly generated PSDs are used. We find that our proposed OK model has an excellent agreement with GCMC simulation, while the commonly used method to convert the excess adsorption to the absolute adsorption without considering the PSD shows noticeable deviations. Moreover, the optimized constant adsorbed phase densities are very different from the commonly used values as 424 kg/m3 and 373 kg/m3. Our work proposes a simple, efficient and accurate empirical model to obtain the absolute adsorption in nanoporous media. This work should provide important insights into accurate characterization methane absolute adsorption and the gas-in-place estimation in shale.

The development of natural/artificial fractures leads to significant differences of the physical properties between the matrix and the fractures, which usually causes serious channeling and low sweep efficiency during CO2 flooding in ultra-low permeability reservoirs, the use of a CO2-responsive smart mobility control system to generate bulk gel by wormlike micelles (WLMs) to mitigate gas channeling has great potentials for enhanced oil recovery (EOR) in ultra-low permeability reservoirs. In this study, five kinds of chemicals with CO2-sensitive groups are screened to measure the apparent viscosity using a rheometer. The experimental results show that the optimum system consists of 4.4 wt% N, N-dimethyl octylamide-propyl tertiary amine (DOAPA) and 2.0 wt% sodium p-toluenesulfonate (SPTS). Subsequently, the plugging capacity and EOR performance of the system are systematically evaluated using core flooding experiments. The optimized system (DOAPA/SPTS) exhibits outstanding plugging capacity for gas channeling with a plugging efficiency of 99.2%. The oil recovery of the CO2 flooding increases by 20.0%. In addition, the thickening mechanism of the CO2-responsive system is studied using rheological experiments and a cryogenic transmission electron microscopy (Cryo-TEM). The shear-thinning behavior demonstrates that the thickening effect of the high-viscosity WLMs is strong in the DOAPA/SPTS-CO2 solution, and the Cryo-TEM results indicate a transition from spherical micelles to the WLMs. The protonation contributes to the formation of the WLMs in the solution during phase transformation process. The results of this study are expected to provide benchmark to select the mobility control agent for CO2 flooding in ultra-low permeability reservoirs.

A garnet-type solid-state electrolyte Li6.4La3Zr1.4Ta0.6O12 (LLZTO) was modified using dopamine to improve the wettability of LLZTO with PEO, allowing 80 wt% LLZTO to be uniformly dispersed in 20 wt% PEO/LiTFSI polymer electrolyte. Transmission electron microscopy and Fourier transform infrared spectroscopy confirmed a 4–5 nm thick polydopamine (PDA) layer coating on LLZTO nanoparticles. The composite LLZTO@PDA/PEO electrolyte was synthesized using a solvent casting method. The composite electrolyte has good compatibility and adhesion with both positive and negative electrodes of Li-ion batteries owing to the superior wetting capability of dopamine. This property allows for improved interfacial contact at the electrode/solid electrolyte interface which can decrease the overall resistance of the battery. With dopamine modification, the conductivity of the composite electrolyte at 30 °C increased from 6.3 × 10−5 S cm−1 to 1.1 × 10−4 S cm−1, and the interfacial resistance between the composite electrolyte and a metallic lithium anode decreased from 308 Ω cm2 to 65 Ω cm2 at 50 °C. The composite electrolyte also demonstrated improved thermal stability.

Production of hydrocarbons from shale is a complex process that necessitates the extraction of multi-component hydrocarbons trapped in multi-scale nanopores. While advances in nanofluidics have allowed researchers to probe thermodynamics and transport in single, discrete nanochannels, these studies present a highly simplified version of shale reservoirs with homogeneous pore structures and/or single-component fluid compositions. In this study, we develop and apply a 30 000-pore nanomodel that captures the inherent heterogeneity in reservoir pore sizes (100 nm pores gated by 5 nm-pores) to study vaporization of a representative natural gas hydrocarbon mixture. The nanomodel matches major North American formations in the volumetric and number contributions of the pore sizes, porosity (10.5%), and ultra-low permeability (44 nD). Combined experimental and analytical results show 3000× slower vaporization owing to the nanoscale throat bottlenecks. At low temperatures, mixture effects reduce rates further with stochastic vaporization of light components in large pores dominating. Collectively this approach captures the coupled complexity of multicomponent, multiphase fluids in multiscale geometries that is inherent to this resource.

Accurate characterization of methane absolute adsorption in shale plays an important role in estimation of gas-in-place and prediction of well productivity. Previously, methane adsorption in shale nanopores was considered as a single-layer structure. However, it has been shown that due to strong fluid-surface interactions, methane can form transition zone between the first adsorption layer and free gas phase. Such transition zone can negatively affect the accuracy of absolute adsorption estimation from excess adsorption, which is the mostly measured adsorption property in experiments. In this work, we use grand canonical Monte Carlo (GCMC) simulations to characterize the transition zone and propose a modified adsorption model. Based on the modified adsorption model, which can explicitly take into account the effect of transition zone, we use Ono-Kondo (OK) lattice model with multilayer structure to calculate the absolute adsorption in each layer and compare with GCMC simulations. The newly proposed OK model with multilayer structure only needs layer width as an input and calculates the density in each layer and subsequently the absolute adsorption by fitting the excess adsorption. While OK model can significantly reduce calculation time, discrepancy from GCMC simulation can be less than 6%. Our work should provide important insights into the accurate characterization of methane absolute adsorption from experimental measurement.