Organic Nanopores Research Articles

Geological characteristics and reservoir properties in the unconventional Montney Formation, southwestern Alberta, Canada

In order to understand the unconventional reservoir characteristics in the Montney Formation, the detailed geological examinations, such as core interpretation, petrographic analysis and the poro-perm measurement (including MICP), have been performed from the Kakwa well, drilled in southwestern Alberta, Canada. The studied Montney section, mostly comprised of fine to coarse siltstone, can be informally subdivided into three distinctive intervals, on the basis of a prominent log marker, inferred to represent a major regional falling and flooding surface. The core description and the log characters have confirmed that the entire section mostly comprises a series of multi-stacked, higher-order parasequences. They are characterized by the coarsening-upward succession, having homogeneous to pinstripe-laminated shale (Facies A), heterolithic siltstone (Facies B), and massive to faintly laminated coarse siltstone (Facies C). The succession is interpreted to be formed in response to a progradational shoreface setting, wherein trace fossils typically show a diminutive and low-diversity suite. The mineralogical analysis has revealed that the cored samples are composed mostly of detrital grains of quartz, feldspar and dolomite with the major cement materials of illite, chlorite and smectite, the ratio of which would be lithofacies-controlled, having a higher proportion of clay and TOC in the more distal facies. Clays, mostly authigenic in origin, commonly occlude primary pores, but disseminated organics contain the pervasive organic nanopores. Pore-throat size distribution shows modal radius (5 to 75 nm) that has a positive correlation with the grain-size variation, but has a negative correlation with respect to the TOC and clay contents. Likewise, the poro-perm system appears to be facies-dependant. The mineralogical and petrographic studies have led to the general conclusions that the poro-perm characteristics are strongly influenced by the pervasive presence of organics and authigenic clays that would fill and occlude the paleopore network. The study results tentatively suggest that the Middle Montney, coarsest and most porous (up to 7%), will have the highest potentiality with respect to the poro-perm system.

Effects of nano-pore wall confinements on rarefied gas dynamics in organic rich shale reservoirs

The advancements in horizontal well drilling and multistage hydraulic fracturing technology enabled us to unfold major sources of hydrocarbon trapped in ultra-tight formations such as organic rich shales. Tremendous gas production from these reservoirs has transformed today’s energy landscape [1]. Even though multi-stage hydraulic fracturing stimulation provides high permeability paths to transfer gas to the wellbore, however, most of the gas is stored in nano-organic pores of the ultra-low permeability shale matrix that needs to be transferred to the hydraulic fractures to be able to be produced. Studies using advanced imaging technologies such as FIB/SEM and low temperature adsorption measurements show that in the organic rich shale gas reservoirs, Kerogen, the finely dispersed organic nano-porous material with an average pore size of less than 10 nm holds bulk of the total gas in place (GIP). The molecular level interactions between fluid–fluid and fluid–solid organic pore walls govern the transport and storage in these organic nano-pores.To understand the high gas production rates from these ultra-tight formations, the objective of this study is to advance our understanding of non-ideal gas dynamics in multiscale pore structure of organic rich shale matrix (i.e., gas storage and transport influenced by adsorption and adsorbed gas transport) and develop a model to quantify these effects under wide range of reservoir conditions. Among different methods used to model gas dynamics in organic nano-pores such as the multi-continuum, molecular dynamics and Monte Carlo, the lattice Boltzmann method (LBM) is more effective method with much less computational cost relative to other techniques. In this study we focus on rarefied gas dynamics in Kerogen organic nano-tubes under wide range of reservoir pressure and temperature conditions using a two dimensional LBM model.In this model the Langmuir-slip boundary condition at capillary walls, convection or darcy flow and diffusive transport (slippage of free gas molecules and surface transport of adsorbed molecules combined) are considered to model gas transport. Different transport mechanisms and their contribution in gas transport is investigated in a large range of Knudsen numbers from continuum flow to transition flow regime under different reservoir conditions. The deviation from classical theory of fluid flow in micro channels such as Knudsen’s minimum in the mass flow rate is investigated and the effect of gas slippage and double slippage on Knudsen minimum is discussed in details. Finally the results are compared with analytical, and semi analytical solutions available in the literature.The LBM model results displays a clear indication that the gas transport in the capillary tube is highly depends on the pore width size, pressure and temperature. The relative impact of pore size, pressure and temperature on maximum gas velocity and gas wall velocity differs at different flow regime conditions. A critical Knudsen number exists at different reservoir conditions, where the anticipated parabolic fluid velocity profile in organic nano-pores alters and shows higher flow rate as capillary widths reduces due to the underlying effect of molecular phenomena of double slippage and the wall confinement. The comparison with traditional continuum Hagen-Poiseuille law, Klinkenberg slip theory, and recent modified versions of Klinkenberg slip flow equations show that the previous models are valid only in the continuum flow regime, however, they fail to capture high gas flow rates at high Knudsen number and transition flow regimes which is the case in most of the shale organic nano-pore conditions [2].This work is not only important for the advancement of shale gas flow simulators, but also for organic rich shale characterization.

Gas Transport Model in Organic Shale Nanopores Considering Langmuir Slip Conditions and Diffusion: Pore Confinement, Real Gas, and Geomechanical Effects

Nanopores are extremely developed and randomly distributed in shale gas reservoirs. Due to the rarefied conditions in shale strata, multiple gas transport mechanisms coexist and need further understanding. The commonly used slip models are mostly based on Maxwell slip boundary condition, which assumes elastic collisions between gas molecules and solid surfaces. However, gas molecules do not rebound from solid surfaces elastically, but rather are adsorbed on them and then re-emitted after some time lag. A Langmuir slip permeability model was established by introducing Langmuir slip BC. Knudsen diffusion of bulk phase gas and surface diffusion of adsorbed gas were also coupled into our nanopore transport model. Considering the effects of real gas, stress dependence, thermodynamic phase changes due to pore confinement, surface roughness, gas molecular volume, and pore enlargement due to gas desorption during depressurization, a unified gas transport model in organic shale nanopores was established, which was then upscaled by coupling effective porosity and tortuosity to describe practical SGR properties. The bulk phase transport model, single capillary model, and upscaled porous media model were validated by data from experimental data, lattice Boltzmann method or model comparisons. Based on the new gas transport model, the equivalent permeability of different flow mechanisms as well as the flux proportion of each mechanism to total flow rate was investigated in different pore radius and pressure conditions. The study in this paper revealed special gas transport characteristics in shale nonopores and provided a robust foundation for accurate simulation of shale gas production.

The effect of different organic solvents on sodium ion storage in carbon nanopores.

In this study fully atomistic grand canonical Monte Carlo (GCMC) simulations have been employed to study the behaviour of an electrolyte salt (NaPF6) and different non-aqueous (organic) solvents in carbon nanopores, to reveal the structure and storage mechanism. Organic solutions of Na+ and PF6- ions at 1 M concentration were considered, based on the conditions in operational sodium ion batteries and supercapacitors. Three organic solvents with different properties were selected: ethylene carbonate (EC), propylene carbonate (PC), and ethyl methyl carbonate (EMC). The effects of solvents, pore size and surface charge were quantified by calculating the radial distribution functions and ionic density profiles. It is shown that the organic solvent properties and nanopore confinement can affect the structure of the organic electrolyte solution. For the pore size range (1-5 nm) investigated in this paper, the surface charge used in this study can alter the sodium ions but not the solvent structure inside the pore.

Ultrathin two-dimensional covalent organic framework nanoprobe for interference-resistant two-photon fluorescence bioimaging.

The complex environment of living organisms significantly challenges the selectivity of classic small-molecule fluorescent probes for bioimaging. Due to their predesigned topological structure and engineered internal pore surface, covalent organic frameworks (COFs) have the ability to filter out coexisting interference components and help to achieve accurate biosensing. Herein, we propose an effective interference-resistant strategy by creating a COF-based hybrid probe that combines the respective advantages of COFs and small-molecule probes. As a proof of concept, a two-photon fluorescent COF nanoprobe, namely TpASH-NPHS, is developed for targeting hydrogen sulfide (H2S) as a model analyte. TpASH-NPHS exhibits limited cytotoxicity, excellent photostability and long-term bioimaging capability. More importantly, compared with the small-molecule probe, TpASH-NPHS achieves accurate detection without the interference from intracellular enzymes. This allows us to monitor the levels of endogenous H2S in a mouse model of cirrhosis.

New Coupled Apparent Permeability Models for Gas Transport in Inorganic Nanopores of Shale Reservoirs Considering Multiple Effects

The study of seepage mechanism in shale gas reservoir has been paid more and more attention. The shale gas reservoirs are rich in nanosized pores. The pores in shale matrix can be divided into organic nanopores and inorganic nanopores. At present, there are many literature studies focusing on establishing a model to analyze the gas transport mechanism in shale organic pores. Some researchers also considered the difference of gas transport in organic and inorganic matrix pores, and a mathematical model of inorganic nanopores has been established. However, for inorganic nanopores, most of the models ignore the effect of irreducible water distribution on gas transport, which leads to overestimating of gas transport capability. In this paper, first, based on the weighting coefficient proposed by Wu, the apparent permeability models are established for inorganic nanopores with two different cross-sectional shapes, which are known as cylindrical capillary and slit nanopores. The influence of irreducible water d...

Matrix–Fracture Interactions During Flow in Organic Nanoporous Materials Under Loading

The transport of natural gas in shale resources is of multiscale and multiphysics nature. The gas transport involves dealing with pores of different length scales and geometrical orientation. Understanding and modeling the interactions of those pores are crucial for proper description of shale matrix deliverability and dynamics. These interactions are less understood at a microscopic scale during the depletion of shale reservoir. In this study, we consider transient flow behavior of a compressible fluid in organic nanoporous material with micro-fractures, or cracks, using a pore network modeling approach. We present a multistep workflow where the transport in the organic nanopores is studied considering the advective–diffusive–adsorptive mechanisms then, coupled with the microcracks for better understanding and optimizing of natural gas organic-rich shale. The natural gas is initially stored in the pore network at high pressure as free and adsorbed fluids and its pressure-driven viscous flow includes additional diffusion mechanisms. The percolation theory is used to obtain some approximations to the organic matrix flow regime coefficients. The organic materials–microcracks coupling term is derived and validated relating the flow rate exchange to the pressure difference with some modifications in order to account for the organic matrix transport dependency on the pressure. The coupling flow exchange term is used to link the local nanoscale heterogeneity to the large scale continuum modeling of shale reservoir. The upscaled model captures the transport exchange during the transient and steady-state flow conditions.

Apparent permeability for liquid transport in nanopores of shale reservoirs: Coupling flow enhancement and near wall flow

Multiple mechanisms of oil transport in inorganic and organic nanopores of shale oil reservoirs are still unclear and possibly more complex than those of gas transport in nanoporous media, due to differences of molecules free path and fluid-solid molecular interactions. The accurate apparent permeability model considering oil transport mechanisms and different pore types is important for macroscale modeling in shale oil reservoirs development. Based on studies of molecular dynamics simulations (MDS), liquid flow through carbon nanotubes (CNTs) and theoretical analysis, a unified apparent permeability model of liquid hydrocarbon flow in the shale is derived coupling different transport mechanisms in inorganic and organic nanopores. The model of oil-wet organic nanopores considers liquid-solid adsorption, while the model of water-wet inorganic nanopores incorporates near wall flow and velocity slip. We then introduce complicated structural parameters including the tortuosity, porosity and total organic carbon (TOC) to develop models from nanotubes into porous media. After that, the proposed model is validated by MDS and experimental results, and the total apparent liquid permeability (ALP) as well as contributions of different mechanisms are studied. The results indicate that, flow enhancement should be considered in the characterization of oil transport in nanopores, and the velocity of oil in inorganic nanopores much faster than that in organic nanopores in this work. For pore radii under 10nm, the total ALP is much larger than intrinsic permeability, and adsorption effect as well as velocity slip in organic matter (OM) and inorganic matter (IM) influence the total ALP slightly when the pore radius is larger than 100nm. In addition, the greater slip length in IM results in greater contributions of oil transport in IM to the total ALP if slip length is less than 10nm. Moreover, the ratio of the total ALP to intrinsic permeability decreases as TOC increases when TOC is larger than 20%. This work focuses on enriching the theoretical research of oil transport in nanopores and provides a unified ALP model for macroscale modeling study in the shale reservoirs development.

Apparent permeability model for real gas transport through shale gas reservoirs considering water distribution characteristic

The accurate knowledge of gas transport mechanisms through shale matrix will significantly advance the development of shale gas reservoirs. At present, the different cross-section shapes for organic and inorganic pores have not drawn much attention. In terms of current literatures, the organic pores are considered as hydrophobic and the inorganic pores is hydrophilic, thus the water film can be adsorbed on the surface of inorganic pore. However, the volume occupied by water film is overlooked and its effect on gas transport capacity has not been investigated ever. In this work, the Beskok’s models are employed, which can be applied to characterize the bulk-gas transport mechanisms through circular nanotubes or slit nanopores with arbitrary aspect ratio. In addition, the organic and inorganic nanopores in shale matrix are assumed as nanotubes and slit nanopores respectively. Considering the presence of adsorbed gas phase, the apparent permeability model for organic pores takes bulk-gas transport regimes, surface diffusion and gas desorption into account. Considering the thickness of adsorbed water film, the apparent permeability model for inorganic matter incorporates the bulk-gas transport mechanisms and effect of water film. More features, such as stress dependence, real gas effect, are included in both models. Based on the proposed permeability models, the influences of pore size, formation pressure, and humidity on apparent permeability for organic/inorganic pores are seriously analyzed. Results show that the surface diffusion will dominate the transport capacity when the organic pore size is less than 2nm. For inorganic pores, it can be concluded that the larger pore radius will obtain the stronger transport capacity. The real gas effect has little influence on apparent gas permeability which can be neglected. The stress dependence, humidity and gas desorption influence the effective radius of nanoscale pores, which have significant effects on transport capacity.

Three-dimensional characterisation of multi-scale structures of the Silurian Longmaxi shale using focused ion beam-scanning electron microscopy and reconstruction technology

China has the largest quantity of technically recoverable shale gas resources in the world. However, the complex, three-dimensional (3D), multi-scale structure of the shale reservoir makes it extremely challenging to fully understand the mechanisms that govern shale gas migration and recovery efficiency. In this study, focused ion beam-scanning electron microscopy (FIB-SEM) was applied to identify the nano- and micron-scale 3D structures, including inter-particle pores, organic matter pores, intra-particle pores and fractures, of shale sampled from the Longmaxi Formation, Sichuan Basin, China. The 3D structural and physical characteristics, such as morphology, porosity, connectivity, and permeability of multi-scale pores and fractures, were analysed using 3D reconstruction techniques and the lattice Boltzmann method (LBM). The results show that the majority of pores in the Longmaxi shale samples varied between 10 and 40 nm in size, although some significantly larger intra-particle pores were also detected. The micro-fractures exhibited higher permeability and gas migration capacity than adjacent nano-pores, and organic matter nano-pores displayed high porosity and good connectivity. This study provides a way to quantitatively characterise the multi-scale structure and its effect on shale gas migration and fracturing potential in the Longmaxi formation, as well as in similar shale reservoirs elsewhere around the world.

Modeling and simulation of gas transport in carbon-based organic nano-capillaries

Modeling of transport of fluids in organic nanopores of shale is associated with complexities due to existence of ultratight pores and strong fluid–solid interactions. In this study, adsorption and transport of three different gases (argon, methane, and neon) are investigated by performing molecular simulations of identical setups of nano-scale carbon capillaries made up of smooth graphite sheets. The simulations are performed for capillaries with 2, 4, 6, and 8nm diameters for a wide range of pressures and pressure gradients. The velocity, density, diffusion coefficients, and viscosities of the gases are computed and compared.Based on the molecular simulation results, as the pressure of the system increases, amount of the adsorbed gas molecules on the capillary walls increases to reach the saturation state. Computed velocity profiles show that for all gases in the capillaries, velocity profiles are plug-shaped. Computed gas velocities from molecular simulations are compared with the velocities predicted by regularized 13-moment model by adjusting the tangential momentum accommodation coefficients (TMAC). The calculated TMAC values are found to be between 0.03 to 0.18 for the pressure range tested. It is found that as the Knudsen number increases, the molecules reflect more specularly in the capillaries. We also investigated the effect of adsorption on TMAC values and found that the TMAC values can be predicted by including the effect of adsorption surface coverage into consideration. Furthermore, it is found that the Knudsen diffusion model underestimates the molecular fluxes in the capillaries by at least one order of magnitude. The corrected and transport diffusivity coefficients decrease as pressure increases and approach one another at low pressures.The viscosity of the gases are calculated for different fugacities and Knudsen numbers based on self-diffusivity coefficients for two capillary sizes of 2 and 4nm. The computed viscosities of all gases decrease as pressure increases. For all gases, the viscosity under confinement are lower than their nominal values. Viscosity values for argon and methane increase approximately linearly with fugacity for both capillaries. The viscosity values of neon for the capillaries are almost the same for fugacities less than 90atm. It is also shown that the viscosity models for gases under confinement are not good candidates to be used in organic nanopores due to adsorption of gases to pore surface.

Oil retention and porosity evolution in organic-rich shales

Petroleum is retained in shales either in a sorbed state or in a free form within pores and fractures. In shales with oil resource potential, organic matter properties (i.e., richness, quality, and thermal maturity) control oil retention in general. In gas shales, organic pores govern gas occurrence. Although some pores may originate via secondary cracking reactions, it is still largely unclear as to how these pores originate. Here we present case histories mainly for two classic shales, the Mississippian Barnett Shale (Texas) and the Toarcian Posidonia Shale (Lower Saxony, Germany). In both cases, shale intervals enriched in free oil or bitumen are not necessarily associated with the layers richest in organic matter but are instead associated with porous biogenic matrices. However, for the vast bulk of the shale, hydrocarbon retention and porosity evolution are strongly related to changes in kerogen density brought about by swelling and shrinkage as a function of thermal maturation. Secondary organic pores can form only after the maximum kerogen retention (swelling) ability is exceeded at Tmax (the temperature at maximum rate of petroleum generation by Rock-Eval pyrolysis) around 445°C (833°F), approximately 0.8% vitrinite reflectance. Shrinkage of kerogen itself leads to the formation of organic nanopores, and associated porosity increase, in the gas window.

Thickness and stability of water film confined inside nanoslits and nanocapillaries of shale and clay

Characteristics of water film thickness and stability within nanopores are topics of great interest for evaluation of initial fluid storage in unconventional reservoirs. Although related researches with thin film on flat substrates have been carefully and extensively considered, the thickness and stability of liquid films affected by nanoscale confinement in nanostructured materials, such as clay minerals and tight rocks, have raised lots of questions.In this work, an approach by considering fluid/pore-wall interactions (surface forces) was developed to describe the phase behavior of thin water film transition into liquid condensation. The calculated results reveal that the instability mechanisms of adsorbed films differs inside slits and capillaries. In slit pores, the coalescence of flat wetting films forms under the action of attractive forces by opposite slit surfaces. Whereas in capillaries, collapse of curved wetting films occurs due to the integrative action of surface force and cylindrical capillary force. Due to the additional capillary action, the total surface interactions inside capillaries are higher than that inside silts, which leads to an easier condensation and thicker film thickness in capillaries.Meanwhile, the phase behavior of adsorbed water film within nanoporous montmorillonite and shale were investigated by water vapor (H2O) adsorption isotherms. Specially, the water distribution characteristics inside single nanopore rather than the whole porous media were also investigated based on the difference of pore size distribution (PSD) between dry and moist samples, and these PSD information was obtained by low temperature (77K) nitrogen (N2) sorption analysis. Our experimental results directly demonstrated the evidence of water condensation in hydrophilic clay samples, e.g., pores <6–7nm would be totally blocked by capillary water. However, a “partial condensation” phenomenon was found in shale samples, e.g., the shale nanopores could not been entirely filled by water even under a high-moisture condition (RH=0.98), which was mainly caused by hydrophobic repulsion of organic minerals. This surface repulsion could prevent water from condensing and likely result in a monolayer water film adsorbed inside these hydrophobic organic nanopores, e.g. graphite. Therefore, in an actual shale system with initial moisture, the storage of water inside organic pores can be neglected while these inorganic micropores blocked by condensate may be unavailable for gas storage or transport.

Liquid permeability of organic nanopores in shale: Calculation and analysis

The contribution of kerogen to oil flow in shale rock is not well understood but is crucial, and understanding the transport behaviors of oil through organic nanopores is important for shale oil reservoir development. Based on relevant MDS (molecular dynamics simulations), experimental and theoretical studies, a mathematical model was derived to calculate the liquid permeability of organic nanopores in shale. The model can incorporate the mechanisms of boundary slip and physical adsorption, and the complicated structural properties are included. The results show the following: (a) Flow enhancement or permeability is linearly related to the pore length. (b) For pore radii under 10nm, the permeability changes slightly. The corresponding equivalent pore radius is 24nm. (c) There is no need to consider the threshold pressure gradient or nonlinear flow characteristics for oil flow in kerogen. (d) For pore radii greater than 200nm, slip is negligible. (e) Physical adsorption cannot obviously influence the permeability of the organic nanopores. (f) For pores larger than 500nm, the mass flux of the physically adsorbed oil is negligible. By the definition of the normalized velocity, the shape of the velocity profile is studied quantitatively to show the dominance of a plug type velocity profile. The relationship between the slip factor and normalized velocity is also derived. As the normalized velocity approaches 1, the slip factor increases rapidly to infinity. This work can help in the understanding of the flow properties of kerogen and will shed light on the development of shale resources.

Modeling Water Leak-off Behavior in Hydraulically Fractured Gas Shale under Multi-mechanism Dominated Conditions

Fracturing-fluid leak-off in fractured gas shale is a complex process involving multiple pore/fluid transports and interactions. However, water leak-off behavior has not been modeled comprehensively by considering the multi-pores and multi-mechanisms in shale with existing simulators. In this paper, we present the development of a comprehensive multi-mechanistic, multi-porosity, and multi-permeability water/gas flow model that uses experimentally determined formation properties to simulate the fracturing-fluid leak-off of hydraulically fractured shale gas wells. The multi-mechanistic model takes into account water transport driven by hydraulic convection, capillary and osmosis, gas transport caused by hydraulic convection, and salt ion transport caused by advection and diffusion. The multi-porosity includes hydraulic fracture millipores, organic nanopores, clay nanopores, and other inorganic micropores. The multi-permeability model accounts for all the important processes in shale system, including gas adsorption on the organics’ surface, multi-mechanistic clay/other inorganic mineral mass transfer, inorganic mineral/hydraulic fracture mass transfer, and injection from a hydraulically fractured wellbore. The dynamic water saturation and pressure profiles within clay and other inorganic matrices are compared, revealing the leak-off behavior of water in rock media with different physicochemical properties. In sensitivity analyses, cases with different clay membrane efficiency, volume proportion of source rock, connate water salinity, and saturation are considered. The impacts of shale properties on water fluxes through wellbore, hydraulic fracture and matrix, and the total injection and leak-off volumes of the well during the treatment of hydraulic fracturing are investigated. Results show that physicochemical properties in both organic and inorganic matrices affect the water leak-off behavior.

Experimental and analytical investigation of adsorption effects on shale gas transport in organic nanopores

Gas production from shale gas reservoirs is determined by original gas-in-place and gas transport mechanism in shale. Gas storage in shale consists of three different states: first, free gas in pores and natural fractures; second, adsorbed gas on the organic and inorganic pore walls; and third, absorbed or dissolved gas into formation water and organic matter. On the other hand, gas transport in shale may be dominated by noncontinuum flow in nanopores, which depends on gas slippage, bulk diffusion, Knudsen diffusion and adsorbed surface diffusion. In this study, a gas velocity model involving all of these parameters is proposed to describe the gas adsorption and Non-Darcy flow effects on gas transport behavior in shale gas reservoirs. Adsorption capacity of six shale core samples is measured by the gravimetric method using magnetic suspension sorption system. Regression analysis of the measured data has been performed using the Simplified Local-Density model coupled with modified Peng-Robinson Equation of State (SLD-PR). The presence of the moisture content is taken into consideration to distinguish between gas adsorption on the surface of organic matter and clay minerals. The hydrophilic feature of clay minerals and hydrophobic feature of organic matter result in water molecules preferring adsorbing on the surface of clays, while gas molecules preferring adsorbing on the surface of organic matter. In the developed velocity model, adsorbed gas is treated as mobile gas molecules adsorbing on the surface of organic nanopores, which moves by means of adsorbed surface diffusion. The surface diffusion velocity is characterized by adsorbed surface diffusion coefficient. Simultaneously, bulk gas is governed by second-order gas slippage, which is calculated using Navier-Stokes (N-S) equation associated with second-order slip boundary condition. Finally, the adsorbed surface diffusion is incorporated into bulk gas flow using Langmuir slip model to account for the total gas flow in the organic nanopores. The results of this study indicate that adsorbed surface diffusion contributes to the enhancement or impediment of total gas flow velocity in organic nanopores. Therefore, properly handling the adsorption effect on gas transport in organic nanopores is critical to correctly understand gas production from shale gas reservoirs.

Study on the Adsorption, Diffusion and Permeation Selectivity of Shale Gas in Organics

As kerogen is the main organic component in shale, the adsorption capacity, diffusion and permeability of the gas in kerogen plays an important role in shale gas production. Based on the molecular model of type II kerogen, an organic nanoporous structure was established. The Grand Canonical Monte Carlo (GCMC) and Molecular Dynamics (MD) methods were used to study the adsorption and diffusion capacity of mixed gas systems with different mole ratios of CO2 and CH4 in the foregoing nanoporous structure, and gas adsorption, isosteric heats of adsorption and self-diffusion coefficient were obtained. The selective permeation of gas components in the organic pores was further studied. The results show that CO2 and CH4 present physical adsorption in the organic nanopores. The adsorption capacity of CO2 is larger than that of CH4 in organic pores, but the self-diffusion coefficient of CH4 in mixed gas is larger than that of CO2. Moreover, the self-diffusion coefficient in the horizontal direction is larger than that in the vertical direction. The mixed gas pressure and mole ratio have limited effects on the isosteric heat and the self-diffusion of CH4 and CO2 adsorption. Regarding the analysis of mixed gas selective permeation, it is concluded that the adsorption selectivity of CO2 is larger than that of CH4 in the organic nanopores. The larger the CO2/CH4 mole ratio, the greater the adsorption and permeation selectivity of mixed gas in shale. The permeation process is mainly controlled by adsorption rather than diffusion. These results are expected to reveal the adsorption and diffusion mechanism of gas in shale organics, which has a great significance for further research.

Metal-organic complex-functionalized protein nanopore sensor for aromatic amino acids chiral recognition.

Chiral recognition at single-molecule level for small active molecules is important, as exhibited by many nanostructures and molecular assemblies in biological systems, but it presents a significant challenge. We report a simple and rapid sensing strategy to discriminate all enantiomers of natural aromatic amino acids (AAA) using a metal-organic complex-functionalized protein nanopore, in which a chiral recognition element and a chiral recognition valve were equipped. A trifunctional molecule, heptakis-(6-deoxy-6-amino)-β-cyclodextrin (am7βCD), was non-covalently lodged within the nanopore of an α-hemolysin (αHL) mutant, (M113R)7-αHL. Copper(ii) ion reversibly bonds to the amino group of am7βCD to form an am7βCD-CuII complex, which allowed chiral recognition for each enantiomer in the mixture of AAA by distinct current signals. The CuII plugging valve plays a crucial rule that holds chiral molecules in the nanocavity for a sufficient registering time. Importantly, six enantiomers of all nature AAA could be simultaneously recognized at one time. Enantiomeric excess (ee) could also be accurately detected by this approach. It should be possible to generalize this approach for sensing of other chiral molecules.

Comparative study on micro-pore structure of marine, terrestrial, and transitional shales in key areas, China

The purpose of this article is to make a comparative study on the pore structure of different sedimentary facies shales developed in typical areas, China. Results show that the surface area (SA) and pore volume (PV) of the over-mature marine shales are in the range of 17.83–29.49m2/g and 3.65–18.26ml/kg, respectively, which are much higher than that of the highly mature transitional and less mature terrestrial shales in the range of 0.9–1.9m2/g and 2.5–10.9ml/kg, respectively. In the view of the pore-size distribution (PSD), marine shales concentrate at the fine mesopores <10nm, while the terrestrial and transitional shales focus on the large-mesopores to fine-macropores (30–70nm). Additionally, the qualitative analysis of hysteresis loops from the nitrogen isotherms reveals that the marine shales are dominated by the inkbottle-shaped pores, which are further confirmed to be the organic pores. While the terrestrial and transitional shales investigated give priority to the slit-shaped pores or wedge-shaped pores, which are further identified as the interlayer pores within clay minerals. Furthermore, different shale components have great differences in the contribution to the SA and PV in different sedimentary facies shales due to the different development of nanopores within (or associated with) different shale compositions. In post-mature marine shales, organic matters (OMs) bearing a large amount of smaller organic nanopores contribute mostly to the SA and PV. For the highly mature transitional shales, it is the illite-smectite mixed clay (I/S) that contributes mostly to the SA and PV because the I/S-hosted nanopores are in the dominated position of the pore system and OMs are almost free of organic pores. As to the less mature terrestrial shales, the I/S minerals together with the OMs jointly contribute to the SA and PV due to the large amount of I/S-hosted pores and some existence of organic pores. Finally, the differences among the three sedimentary facies shales in terms of the pore space, suggest that the marine shales in the South China likely possess greater potential for shale gas than do the terrestrial and transitional shales in North China.

Organic shale wettability and its relationship to other petrophysical properties: A Duvernay case study

In this study, we conduct spontaneous imbibition tests and measure air-oil and air-brine contact angles of nine twin core plugs from five wells drilled in the Duvernay Formation, which is a source rock located in the Western Canadian Sedimentary Basin (WCSB). We investigate wettability of the shale samples with a wide range of TOC (2.2–6.6wt%), effective porosity (2.0–6.2% BV), and kerogen maturity (wet-gas, dry-gas, and over-mature). We characterize the samples by measuring the effective porosity, pressure-decay permeability, oil saturation, bulk density, matrix density, mineralogy, total organic carbon (TOC) content, and conducting rock-eval pyrolysis tests. To investigate the effects of pore connectivity, we also measure spontaneous imbibition and contact angles of oil and water on crushed shale packs and compare the results with those of similar tests on the core plugs. We also investigate the crossplots of effective porosity, pressure-decay permeability, bulk density, matrix density, oil saturation, and TOC content, by using 130 data points from samples of the five wells.Analysis of the data reveals a positive correlation of TOC content with effective porosity, pressure-decay permeability, and oil saturation of the samples. Bulk density and matrix density of the core samples decrease with increasing the TOC content. The crossplots indicate that the majority of pores exist in the organic matter of the samples and these organic pores have high affinity towards oil. Scanning Electron Microscope (SEM) and energy-dispersive X-ray spectroscopy (EDS) analyses also demonstrate an abundant number of small nanopores within the organic matter. These hydrophobic small nanopores with diameters <100nm may explain high imbibed volume of oil compared with that of brine, and also late equilibrium of oil imbibition. SEM and EDS analysis also show large micropores bordered by inorganic minerals. According to Handy's model, these hydrophilic micropores with diameters >1000nm may explain early equilibrium of brine in spontaneous imbibition experiments. We define pore wettability index of oil (PWIo) and brine (PWIw) based on the imbibition rate of oil and brine, respectively. PWIo is greater than PWIw in all spontaneous imbibition tests. Higher PWIo compared with PWIw indicates that oil preferentially flows through smaller pores while brine prefers to flow through larger pores. We also define oil wettability index (WIo) based on the equilibrium imbibed volume of oil and brine. The results of spontaneous imbibition experiments show that the samples with higher TOC content and effective porosity have higher WIo. Positive correlations of WIo with TOC content and effective porosity suggest that the majority of hydrophobic connected pores exist in the organic part of the rock. In addition, we observe negative correlation of WIo with oxygen index (OI). This observation can be explained by 1) higher number of organic nanopores, and 2) stronger oil-wetness of kerogen in samples with higher kerogen maturity (lower OI).