Inorganic Pores Research Articles

Determination of inorganic and organic permeabilities of shale

Shale oil resources have become important energy supplies worldwide, but their storage features and flow mechanisms remain unclear. It is now well-accepted that shale formations are complex systems with both inorganic and organic contents. This study aims to characterize the permeabilities for inorganic and organic pore systems separately in shale samples using an innovative modeling approach validated with experimental data. Oil and water vacuum–imbibition tests were first conducted along with helium porosity measurements for four shale rock samples. A mathematical model considering imbibition and diffusion was then proposed and used to match the lab-measured oil and water imbibition curves. The critical parameters for these shale samples, including inorganic/organic porosities, fluid saturations, and permeabilities were successfully determined using this approach. Among all the samples in the study, the results showed that 33.93 to 40.54% of total oil in place was stored inside kerogen as either the free oil within the organic pores or the dissolved oil. Moreover, the flow of this part of the oil was controlled by the organic permeability as well as by the diffusion coefficient, which was different than the flow character of oil in the inorganic pore system. The organic permeabilities of the samples used in this study were between 2.24 × 10−6 and 1.59 × 10−5 md, which were 243 to 2741 times less than each sample's corresponding inorganic permeability. The sensitivity analysis indicated that organic permeability significantly affected the oil imbibition rate. The proposed methodology should be adopted in future reservoir characterizations, and the determined permeabilities for both inorganic and organic pore material should accordingly be considered in future reservoir simulations in order to accurately describe fluid flow in shale reservoirs.

Characteristics of wufeng-longmaxi formation shale gas sweet layer: a case study of weiyuan-rongchang block in the south of sichuan basin, China

Taking the typical shale well of the Wufeng-Longmaxi Formation in the Weiyuan shale gas block of the South Sichuan Basin as an example, based on core observation, core slice, ar-ion milling SEM, physical property test, X-ray diffraction, geochemical analysis and on-site gas content test, the author systematically evaluated the Wufeng-Longmaxi geological sweet layer from the aspects of petrology, mineral composition, organic geochemistry, hydrocarbon-generating organism, physical property, pore type and gas content.The research shows that the lithology of the geological sweet layer in Weiyuan area is mainly composed of black carbonaceous shale, and laminae are developed. Compared with the Jiaoshiba area, the carbonate mineral content is higher and the quartz mineral content is relatively lower. The sweet layer has high TOC, and is at a stage of high maturity. It is rich in hydrocarbon-generating organism such as graptolites, algae, sponge bones and bacteria. The inorganic pores and organic pores of the sweet layer are well developed. The inorganic pores are mainly clay mineral pores, feldspar alteration pores and intercrystalline pores of pyrite. In terms of gas content, it has the characteristics of high gas content and high Initial dissipation rate, which provides a possibility for high yield and stable production of fracturing in this layer.The geological sweet layer has high organic carbon content, is rich in hydrocarbon-generating organisms, has a large potential for gas generation, and generated enough gas after a period of high mature evolution; at the same time, a large number of inorganic pores and organic pores generated in diagenetic evolution, these pores provide space for shale gas generation, as the same time, it increases the permeability of the sweet layer. The study area has good preservation conditions, it has favorable top and bottom Stratum conditions, and does not have large destructive fractures and destructive fluid activities, The above factors make the shale gas enriched and preserved, which provides the possibility of high and stable yield after fracturing.

Mass flow rate prediction of shale gas considering gas diffusion and water film evaporation

The difference between organic and inorganic matters in shale matrix has significantly influence on the transport capacity of shale gas and the total production of shale gas further. Previous studies have demonstrated that the organic pores are hydrophobic and the inorganic pores are hydrophilic. Therefore, the water film can be adsorbed on the walls of the inorganic pores. However, the evaporation of water film in inorganic pore is often overlooked due to the analytical challenge and the effect of the water film evaporation on gas transport capacity is rarely discussed. Thus, it is important to accurately predict mass flow rate of the shale gas through a single nanopore whether it is organic or inorganic. In this article, the mass flow rate prediction model of the organic pore is developed firstly, which considers the interactions of slip flow, gas adsorbed at pore walls, surface diffusion for adsorbed gas and gas diffusing from the kerogen which contains dissolved shale gas in organic pores at nanoscale. This model is then used to investigate the influences of initial pressure, pressure gradient, and thickness of kerogen on the gas mass flow rate. For inorganic pores, the mass flow rate prediction model is developed secondly and the interactions of water film and the evaporation of water film have been considered. The influence of evaporation, initial humidity, water–methane diffusivity is investigated on the gas mass flow rate. Results show that diffusion from kerogen plays an important role in the transport capacity of shale gas. Both higher pressure gradient and thicker kerogen can contribute to higher gas mass flow rate and higher diffusion from kerogen. Higher initial pressure and thicker kerogen can contribute to the lower shale gas desorption. The thicker kerogen can contribute to the higher surface diffusion. The evaporation in inorganic pore should not be ignored, because it impacts gas mass flow rate and can contribute to the higher flow rate. Experimental data was compared with our prediction model, which proves the correctness and validity of our model.

Recovery mechanisms of hydrocarbon mixtures in organic and inorganic nanopores during pressure drawdown and CO2 injection from molecular perspectives

Competitive adsorption of hydrocarbon mixtures (C1-C2-C3) as well as CO2 in shale nanopores is of critical importance to CO2 enhanced shale gas recovery. While experiments can measure mixture adsorption from macroscopic perspective, the underlying mechanism at nanoscale is still ambiguous. In this work, we use Grand Canonical Monte Carlo (GCMC) simulations to study competitive adsorption of C1-C2-C3 and C1-C2-C3-CO2 mixtures in organic and inorganic pores at reservoir conditions. The dependences of competitive adsorption behavior on rock property, pore size, and fluid composition are explicitly examined. We find that while C1 in the adsorption layer can be readily recovered during pressure drawdown, C2 and C3 are trapped in pores, especially in organic micropores. Injected CO2 can effectively recover each component in the adsorption layer in organic pores, while in inorganic pores, the adsorption layer is dominated by CO2 molecules, displacing all hydrocarbon components. CO2 injection is an effective method to recover the heavier hydrocarbons. While pressure drawdown is more effective in inorganic pores, CO2 injection performs better in organic pores. Our study should provide fundamental understanding about the recovery mechanisms of shale gas mixtures in various rocks and sheds light on the efficiency of CO2 enhanced recovery in shale gas reservoirs.

Characterization of pore structures and gas transport characteristics of Longmaxi shale

Multiscale pore structures of shale conjunctionally determine the gas storage and transport properties of gas shale reservoirs. To investigate the complex pore structures and gas transport in the ultra-tight porous media, a combination of petrophysical and scanning measurements is adopted in this study. Five shale samples of the main productive layers from four wells (Long 11 sub-members of Longmaxi Formation) in southeast Sichuan Basin, China are analyzed. Based on scanning electron microscope (SEM) image, different types of organic pores and inorganic pores are quantitatively analyzed. A method for identification of organic and inorganic pores from SEM images is developed. And a comparison between the pores identified from SEM and gas adsorption (N2 and CO2 adsorption) is conducted. Results show that the main part of inorganic pores are mesopores, and the organic pore size distributions tend to be lognormal with the peak pore size from 10 nm to 30 nm. Results also show that the gas storage space obtained by SEM is several times to several tens of times larger than that obtained by gas adsorption method. The permeability of OM and shale cores is also compared. The permeability is strongly anisotropic and all those samples show a significant non-Darcy effect. Finally, the relationship between the pore structures and gas transport behavior is studied, and the high quality shale samples are identified considering their gas storage and transport behaviors.

Methodology of three-dimensional visualization and quantitative characterization of nanopores in coal by using FIB-SEM and its application with anthracite in Qinshui basin

Analysis of the three-dimensional (3D) visualization and reconstruction methods of nanopores, and its morphology and connectivity are the key to explore the storage and migration mechanism of coalbed methane (CBM). The Bofang (BF) sample collected from the Qinshui basin was scanned by the focused ion beam scanning electron microscopy (FIB-SEM), which can simultaneously image the nanopores through 2D slice image and 3D reconstruction image. Firstly, the 2D morphology and development characteristics of nanopores were analyzed. Secondly, the 3D visualization and reconstruction of nanopores were carried out. Then, the pore connectivity, permeability, and geometric characteristics were discussed. Finally, the effect of pore structure on the storage and migration of CBM was emphatically analyzed. The results show that the organic pores, inorganic pores, shrinkage-induced pores and micro-fractures were developed in coal, and their morphology and connectivity were significant differences. The pores and throats can be extracted from the digital cores with sub-volume of 4.9 × 4.9 × 4.5 μm3, the pore number and throat length (avg.) of BF sample are 21951 and 18.2789 nm, respectively, the porosity and permeability of BF sample is 2.004% and 4.405 × 10−3 mD, respectively, which all indicates the BF reservoir has good storage and connectivity capacity. For pores <50 nm, the number, volume and area indicate that the BF sample has good storage capacity. For pores >200 nm, the pores are all interconnected, which indicates the BF sample can provide effective channels for CBM migration. The distribution of pores and throats and their geometric and topological structures indicate that the BF sample has good migration ability. This study on the methodology of 3D visualization and quantitative characterization of nanopores using FIB-SEM can broaden the research method of pores, and lay good foundations for studying the storage and migration of CBM.

An improved transport model of shale gas considering three-phase adsorption mechanism in nanopores

For the shale gas transport model in nanopores, researchers recently pay more and more attention to the existence of water phase. However, the effect of water film on the gas transport is still not clearly understood. In this paper, we considered the existence of water film on inorganic shale pore surface and introduced the adsorption mechanism of methane-water film-shale clay three-phase (gas-liquid-solid) to the shale gas transport model. Then, we modified the expression of porosity and derived a new transport equation of shale gas considering the adsorption mechanism of three-phases in nanopores. Using the finite element method, we solved the equation and analyzed the effect of water film. Finally, the range of water film effect was analyzed by defining the offset ratio. The results show that: (1) The existence of water film has negative effects on physical quantities, such as effective porosity and apparent permeability. When the water molecular coverage ratio reaches to 1, the decrease of porosity can be about 18.1%; (2) The existence of water film reduces the gas production rate and accumulative gas production. When the water molecular coverage ratio reaches to 1, the gas accumulative production decreases about 49.6%; (3) The pore radius which has significant water film effect is very small. Furthermore, the smaller of the pore size, the more significant the water film effect is. Also, it can be found that the effect of water film on porosity can be ignored with when pore radius exceeds 29 nm. When the pore radius is larger than 11 nm, the effect of water film on kapp/kd can be ignored.

Microemulsion Effects on Oil Recovery From Kerogen Using Molecular-Dynamics Simulation

Summary Source rocks contain significant volumes of hydrocarbon fluids trapped in kerogen, but effective recovery is challenged because of amplified fluid/wall interactions and the nanopore–confinement effect on the hydrocarbon–fluid composition. Enhanced oil production can be achieved by modifying the existing molecular forces in a kerogen pore network using custom–designed targeted–chemistry technologies. The objective of this paper is to show that the maturation of kerogen during catagenesis relates to the qualities of the kerogen pore network, such as pore size, shape, and connectivity, and plays an important role in the recovery of hydrocarbons. Furthermore, using molecular–dynamics (MD) simulations, we investigated how the transport of hydrocarbons in kerogen and hydrocarbon recovery can be altered with the delivery of microemulsion and surfactant micelles into the pore network. New 3D kerogen models are presented using atomistic modeling and molecular simulations. These models possess important chemical and physical characteristics of the organic matter of the source rock. A replica of Type II kerogen representative of the source rocks in the Permian Basin in the US is used for the subsequent recovery simulations. Oil–saturated kerogen is modeled as consisting of nine different types of molecules: dimethyl naphthalene, toluene, tetradecane, decane, octane, butane, propane, ethane, and methane. The delivered microemulsion is an aqueous dispersion of solvent–swollen surfactant micelles. The solvent and nonionic surfactant present in the microemulsion are modeled as d–limonene and dodecanol heptaethyl ether (C12E7), respectively. MD simulation experiments include two stages: injection of an aqueous–phase microemulsion treatment fluid into the oil–saturated kerogen pore network, and transient flowback of the fluids in the pore network. The used 3D kerogen models were developed using a representative oil–sample composition (hydrogen, carbon, oxygen, sulfur, and nitrogen) from the region. Simulation results show that microemulsions affect the reservoir by means of two different mechanisms. First, during the injection, microemulsion droplets possess elastic properties that allow them to squeeze through inorganic pores smaller than the droplet's own diameter and to adsorb at the kerogen surfaces. The solvent dissolves in the oil phase and alters the physical and transport properties of the phase. Second, the surfactant molecules modify the wettability of the solid kerogen surfaces. Consequently, the recovery effectiveness of heavier oil fractions is improved compared with the recovery effectiveness achieved with surfactant micelles without the solubilized solvent. The results indicate that solubilized solvent and surfactant can be effectively delivered into organic–rich nanoporous formations as part of a microemulsion droplet and aid in the mobilization of the kerogen oil.

Pore characteristics and evolution of Wufeng–Longmaxi Fms shale gas reservoirs in the basin-margin transition zone of SE Chongqing

At present, researches on the pore evolution of shale reservoir and its evolution mechanism are still at such a groping stage that a consensus has not yet reached. Based on core analysis and thermal simulation experiments, the pore types, pore structures and pore-size change rules of shale gas reservoirs of Upper Ordovician Wufeng–Lower Silurian Longmaxi Fms in the southeastern (SE) Sichuan Basin and its basin-margin transition zone (hereinafter referred to as the basin-margin transition zone of SE Chongqing) were studied by means of argon ion polishing–scanning electron microscopy (SEM) and atomic force microscopy. Then, the evolution characteristics of organic pores were discussed, and the influence of associated minerals on pore evolution was analyzed. Finally, a pore evolution model for the shale gas reservoirs in this area was established. And the following research results were obtained. First, three types of reservoir spaces are mainly developed in the high-quality shale reservoirs of Wufeng–Longmaxi Fms in this area, including fracture, inorganic pore and organic pore. And the organic pores provide the primary reservoir space of shale gas, which can be divided into four categories, i.e., amorphous kerogen pores, structured kerogen pores, asphaltene pores and paleontology fossil pores. Second, organic contracted fractures are related to the contraction of organic matters, first appearing on one side of the organic matters and then becomes wider and wider with the increase of temperatures. Third, organic pores are mostly the “spongy” pores distributed densely inside the organic matters. When Ro is in the range of 1.56–3.50%, macropores and mesopores are dominant. And when Ro exceeds 3.50%, macropores decrease while mesopores and micropores increase. Fourth, the types of organic matters and the content of associated minerals (e.g. clay minerals, siliceous particles and pyrite) play an important role in the development of pores. In conclusion, the pore evolution law of Wufeng–Longmaxi shale in the basin-margin transition zone of SE Chongqing is that with the increase of burial depth, inorganic porosity decreases significantly, organic porosity increases first and then decreases, and the total porosity shows a change trend of decreasing first, then increasing and finally decreasing continuously.

Homogenization approach for liquid flow within shale system considering slip effect

In the last years, the huge success of shale gas and oil exploitation in North America and enhanced oil recovery by injecting carbon dioxide have attracted more attentions in petroleum industry. The reasonable scheme for shale oil production is a key step for sustainable and high-efficiency products of shale resources, which is dependent on the basic law of liquid flow.In this paper, a multiscale model is established based on homogenization theory to investigate the law of liquid flow within shale system. Considering the results of molecular dynamics simulation, the Navier-Stokes equation coupled with slip boundary is used to describe the liquid flow within microscale domain and the slip-corrected Darcy-like transport model in which clear physical meaning can be shown for every parameter can be derived for macroscale domain. In order to validate derived model, three cases including water and oil flow within simple nanopores are implemented and the results show that homogenization models match well with the results of molecular dynamics simulation for water flow with different contact angle and oil flow within inorganic pore. However, high-order slip-corrected model will deviate from the molecular dynamics simulation for oil flow within simple organic pore when pore size is smaller than 5.24 nm. Then the fractal porous medias are reconstructed based on Monte Carlo simulation and the several critical parameters are discussed. Finally, the results of homogenization model are applied in reservoir scale model to investigate shale oil production performance for economic evaluation and production optimization.

Nanoscale confined gas and water multiphase transport in nanoporous shale with dual surface wettability

Fluid transport in nanoporous shale is known to be affected by the nanoscale fluid transport mechanisms, surface wettability and heterogeneous pore structure. The pores of shale are believed to be dual surface wettability with gas-wet organic pores and water-wet inorganic pores. Investigation on the nanoscale multiphase transport behavior in dual surface wettability nanoporous shale has practical implication in understanding inject water distribution during injected water flow in and flow back process. In this study, we propose a nanoscale gas and water multiphase pore network transport model to study nanoscale confined gas and water transport behavior in dual wettability nanoporous shale. A 3-D shale pore network model is constructed from 3-D image that is reconstructed from 2-D shale SEM image of organic-rich sample. Water transport considers the boundary slip length determined by the contact angle. Bulk gas transport in inorganic pores considers slip effect while bulk gas transport and surface diffusion for adsorbed gas are both considered in organic pores. Injected water flow in process is modeled by water displacing gas process while injected water flow back process is modeled by gas displacing water process. Gas and water relative permeabilities during injected water flow in and flow back process at different TOC volumes and inorganic pore contact angle are analyzed in detail and are compared with relative permeabilities without nanoscale transport mechanisms. Study results reveal that nanoscale gas and water relative permeabilities are influenced by the total organic carbon (TOC) in volumes and inorganic pore water contact angle while nanoscale transport mechanisms influence on the relative permeabilities can be neglected.

Multi-scale pore network modelling of fluid mass transfer in nano-micro porous media

It is widely accepted that pore size distribution and spatial pore connectivity directly impact on the macroscopic porous medium transport properties. Therefore it is indispensable to characterize nano-micro porous media like shale with multi-scale pore structure to accurately assess fluid transport properties. In this study, we propose a multi-scale pore network model to estimate the fluid transport properties. A 3D binary inorganic porous structure model is constructed from a section of scanning electron microscopy (SEM) image which only images large scale inorganic pores and its corresponding inorganic pore network is extracted by the maximal ball fitting method. The nano-porous organic matter is treated as the virtual throat which is embedded in series or parallel connection with the inorganic throat on the original inorganic pore network. Three parameters namely the ratio of total amount of the virtual throat to the total amount of the inorganic throat, the proportion of virtual throat in parallel connection with the inorganic throat and average organic pore radius inside the organic matter are applied to analyze the impact of multi-scale pore structure characteristic on fluid transport properties. The constructed multi-scale pore network model accounts for the organic matter distribution, organic matter total volume, organic pore size, inorganic pore structure and connectivity characteristic between organic and inorganic system all together. Nano-micro scale fluid transport mechanisms are considered in modelling fluid mass transfer. Key analysis results indicate that the fluid mass transfer in nano-micro porous media is influenced by the nano-porous organic matter distribution pattern and it’s local volume. The series connection of nano-porous organic matter and the increase of virtual throat amounts significantly decrease the fluid transport ability. Furthermore, the established multi-scale pore network model is used to interpretate laboratory pressure pulse decay response curve.

Chemical Compositions and Distribution Characteristics of Cements in Longmaxi Formation Shales, Southwest China

Shale gas resources have been regarded as a viable energy source, and it is of great significance to characterize the shale composition of different cements, such as quartz and dolomite. In this research, chemical analysis and the multifractal method have been used to study the mineral compositions and petrophysical structures of cements in shale samples from the Longmaxi Formation, China. X-ray diffraction, electron microprobe, field emission scanning electron microscopy, cathodoluminescence microscopy and C-O isotope analyses confirmed that cements in the Longmaxi Formation shales are mainly composed of Fe-bearing dolomite and quartz. Fe-bearing dolomite cements concentrate around dolomite as annuli, filling micron-sized inorganic primary pores. Quartz cements in the form of nanoparicles fill primary inter-crystalline pores among clay minerals. Theoretical calculation shows that the Fe-bearing dolomite cements formed slightly earlier than the quartz cements, but both were related to diagenetic illitization of smectite. Moreover, multifractal analysis reveals that the quartz cements are more irregularly distributed in pores than the Fe-bearing dolomite cements. These results suggest that the plugging effect of the quartz cements on the primary inoraganic pore structures is the dominant factor resulting in low interconnected porosity of shales, which are unfavorable for the enrichment of shale gas.

Image-based core-scale real gas apparent permeability from pore-scale experimental data in shale reservoirs

This paper presents a new upscaling method to derive the core-scale apparent gas permeability from an improved pore-scale permeability model and experimental data, with more rigorous incorporation of varying gas storage/transport mechanisms in nano/micro pores. First, in use of SEM images of a gas-rich shale field example in Sichuan Basin from our lab, pore network models of inorganic-matter (IOM) and organic-matter (OM) are characterized by using a digital-core technique. Next, an improved pore-scale real gas apparent permeability is modeled rigorously for both IOM/OM, respectively, with 1) bulk gas transport, gas adsorption, surface diffusion, pore-size confined phase behavior, and stress-dependent rock properties and 2) an additional reduction in inorganic pore sizes by water film adhered on pore surfaces. Core-scale permeability is then derived by assembling the permeabilities of stochastically distributed IOM/OM patches with different pore network models properties using the Monte Carlo sampling method. The new core-scale permeability model is validated by pulse-decay permeability experiment. Moreover, the representative elementary volume (REV) size is determined by analyzing the relative standard deviation of apparent gas permeability in cases with different sample sizes. The contributions of different gas transport mechanisms are discussed, and the impacts of stress-dependence for several field examples (i.e., Sichuan, Pierre and Barnett Basins) and water film with varying relative humidity (RH) on core-scale apparent permeability are analyzed. This work provides an effective approach to determine the core-scale shale permeability by directly using pore-scale experimental data, which is a common challenge in the unconventional resources.

A 3D multi-mechanistic model for predicting shale gas permeability

Shale gas reservoir consists of multiple media, including organic matter, inorganic matrix, and natural fracture. The flow of methane in shale system exhibits multiple mechanisms, such as Knudsen diffusion, surface diffusion, adsorption, and phase behavior. However, previous studies don't take these factors into account simultaneously to predict shale gas permeability. Here, we develop a 3D multi–mechanistic model to overcome this drawback. Using a classification algorithm, we first divide two pore size distributions (PSDs) of organic and inorganic pores. Then we measure the gas permeabilities of different pore spaces, respectively. Regarding organic pores, we consider Knudsen diffusion, surface diffusion, and adsorption. For inorganic pores, we only take Knudsen diffusion into account. Both models consider real gas effect and phase behavior. In natural fractures, we use Poiseuille law to obtain fracture permeability. After that, on the basis of embedded discrete fracture model (EDFM), we incorporate the effect of three pore types (natural fracture, organic and inorganic pores) to measure shale gas permeability. To verify the reliability of our model, we compare the result with the data from documented studies. Through sensitivity analysis, we can draw several conclusions as follows. Natural fracture has the greatest impact on permeability, followed by inorganic pore and organic pore. Owing to the horizontally oriented natural fractures, the permeability in horizontal direction is typically higher than that in vertical direction. As the inorganic pore size increases, permeability increases. While increasing organic pore size, the overall permeability will first drop and then pick up. The difference of the overall permeability caused by phase behavior and real gas effect is minor. Our proposed model can be used as an effective and comprehensive tool to predict shale gas permeability.

How Hydraulic Properties of Organic Matter Control Effective Liquid Permeability of Mudrocks

In organic-rich Mudrocks, porous organic matter embedded within mineral matrix along with inorganic pores forms a dual porosity–permeability (ϕ–k) system. How hydraulic properties of organic matter embedded in the mineral matrix contribute to bulk liquid flow however is not well understood. Using computational methods, Navier–Stokes equations are coupled with Brinkman equations for dual (ϕ–k) mineral matrix–organic matter domains obtained from a focused ion beam–scanning electron microscope (FIB-SEM) image set of an organic-rich Murdock and a series of idealized two-dimensional (2D) pore–organic matrix domains. Results of sensitivity analysis show that variations in organic matter permeability cause variations in effective permeability, which follow ‘S-shaped’ characteristics curve on log–log scale. Hydraulic coupling between the dual (ϕ–k) domains shows magnification of the coupled flow behavior when permeability of organic matter is on the same order as the permeability of the connected inorganic pores. The effect of coupled flow becomes negligible when the permeability of organic matter is 102 higher or lower than the permeability of the connected inorganic pores. The fraction of maximum change in magnitude of effective permeability (Im) is found to be exponentially dependent on organic matter–pore channel fraction (f), i.e., Im ∝ e0.77f, for 0 < f < 5. The maximum contribution of organic matter on bulk liquid flow and a large variation in fluid flow velocities are found to be dependent on both the proportion of organic matter and length scale of investigation, indicating that the µm-scale FIB-SEM domains are far from the scale of representative elementary volume (REV). This study, however, describes how the hydrodynamic coupling of dual ϕ–k porous media contributes to emergent bulk liquid flow in organic-rich Mudrocks, and likely in similar dual ϕ–k porous media encountered within engineered systems to the ones found in nature.

Tectonic and Thermal Controls on the Nano-Micro Structural Characteristic in a Cambrian Organic-Rich Shale

Until recently, the characteristics of nano-microscale structures in the naturally deformed, overmature, marine shales were poorly known. Thermally overmature Lujiaping shales in the complex tectonic area of the northeast part of the upper Yangtze area, China have experienced strong tectonic deformation and are considered as potentially important strata for shale gas exploration. Naturally deformed samples from the main source rocks are selected from the Lower Cambrian Lujiaping Formation in the Dabashan Thrust-fold Belt to investigate nanometer- to micrometer-sized structures. A combination of scanning electron microscope (SEM), low-pressure nitrogen adsorption (LPNA), and low-field nuclear magnetic resonance (NMR) suggests that the pore types are dominantly fracture-related pores with a lesser abundance of mineral-hosted pores. These two pore types account for the 90% of total pore space. Organic matter (OM)-hosted pores are rare and make up a small part of the pore systems (less than 10%) due to high thermal maturity and intensive tectonic compression. Overall, the Lujiaping deformed, overmature samples have abundant nanometer- to micrometer-sized inorganic pores. High-resolution SEM images provide direct evidence of the formation of nano- and microsized structures such as OM–clay aggregates and silica nanograins. OM–clay aggregates are commonly observed in samples, which also exhibit abundant open microfractures and interparticle pores. Quartz can occur as silica nanograins and botryoids typically 20–100 nm in size, which may influence porosity through the creation or occupying interparticle pore space.

Geological Factors Controlling the Accumulation and High Yield of Marine‐Facies Shale Gas: Case Study of the Wufeng‐Longmaxi Formation in the Dingshan Area of Southeast Sichuan, China

The main geological factors controlling the accumulation and yield of marine‐facies shale gas reservoirs are the focus of the current shale gas exploration and development research. In this study, the Wufeng‐Longmaxi Formation in the Dingshan area of southeast Sichuan was investigated. Shale cores underwent laboratory testing, which included the evaluation of total organic carbon (TOC), vitrinite reflectance (Ro), whole‐rock X‐ray diffraction (XRD), pore permeability, and imaging through field emission scanning electron microscopy (FE‐SEM). Based on the results of natural gamma ray spectrum logging, conventional logging, imaging logging, and seismic coherence properties, the exploration and development potential of shale gas in the Dingshan area have been discussed comprehensively. The results showed that (1) layer No. 4 (WF2‐LM4) of the Wufeng‐Longmaxi Formation has a Th/U ratio &lt;2 and a Th/K ratio of 3.5‐12. Graptolites and pyrite are relatively abundant in the shale core, indicating sub‐high‐energy and low‐energy marine‐facies anoxic reducing environments. (2) The organic matter is mainly I‐type kerogen with a small amount of II1‐type kerogen. There is a good correlation among TOC, Ro, gas content, and brittle minerals; the fracturing property (brittleness) is 57.3%. Organic and inorganic pores are moderately developed. A higher pressure coefficient is correlated with the increase in porosity and the decrease in permeability. (3) The DY1 well of the shale gas reservoir was affected by natural defects and important late‐stage double destructive effects, and it is poorly preserved. The DY2 well is located far from the Qiyueshan Fault. Large faults are absent, and upward fractures in the Longmaxi Formation are poorly developed. The well is affected by low tectonic deformation intensity, and it is well preserved. (4) The Dingshan area is located at the junction of the two sedimentary centers of Jiaoshiba and Changning. The thickness of the high‐quality shale interval (WF2‐LM4) is relatively small, which may be an important reason for the unstable production of shale gas thus far. Based on the systematic analysis of the geological factors controlling high‐yield shale gas enrichment in the Dingshan area, and the comparative analysis with the surrounding typical exploration areas, the geological understanding of marine shale gas enrichment in southern China has been improved. Therefore, this study can provide a useful reference for shale gas exploration and further development.

Fluid distribution and gas adsorption behaviors in over-mature shales in southern China

To better understand the mechanism of hydrocarbon accumulation and fluid migration in Chinese shales, several samples from two leading marine shales (Longmaxi and Niutitang) were collected for geochemical and mineral analysis, the characterization of pore structure, preliminary studies on fluid flow, and the distribution and investigation of different methane adsorption behaviors. Firstly, the Longmaxi and Niutitang marine shales were found to be in an over-matured stage and dry gas window. Pore structures and connectivity were characterized by field emission - scanning electron microscopy (FE-SEM). The SEM images showed that the micro-fracture, interparticle pores, and organic pores had better connectivity than intraparticle pores. Results from contact angles indicated that the Longmaxi and Niutitang shales tended to have higher affinities for oil rather than for water. The connectivity of pores, distribution of fluids (water and gas) and fluid flow behaviors in the over-matured shale were analyzed using spontaneous imbibition (SI) and tracer diffusion tests. It was found the tracer fluids flow in the way of network flow inside of shale matrix. The connected pore network may be the main path for fluid migration in shale. Additionally, a gravimetric isothermal adsorption experiment was applied to assess methane adsorption capacity in shale. Shale samples with higher total organic carbon (TOC) contents had higher methane adsorption capacities. Organic matter (including kerogen and bitumen), had much greater adsorption capabilities than inorganic minerals (quartz, clay, and others). Finally, the fluid distribution patterns in over-matured marine shale were studied. Shale gas was originally generated in organic matter and then migrated out through connected pores, under differential pressure, between internal and external organic matter hydrocarbon generation areas. These hydrocarbons replaced the water in the pores. Therefore, shale gas may adsorb in organic pores and is freely stored in connected inorganic pores, with bound water, whereas isolated pores are saturated with water. Two different adsorption patterns on mineral surfaces (organic matters and inorganic minerals) were established to explain the different shale gas adsorption behaviors in organic pores and connected pores, with bound water.

Enhanced water flow and apparent viscosity model considering wettability and shape effects

Understanding the enhanced liquid flow behaviors in nano-scale elliptic pores with different surface wettability has tremendous implications in science and engineering, such as water purification and shale oil recovery with abundant irregular circular (elliptic) pores. In this study, the apparent viscosity and enhancement factor model are proposed considering boundary slip velocity and effective viscosity, which is related to the contact angle, pore dimensions and shapes, and the boundary slip velocity depends on the no-slip Hagen-Poiseille equation depending on near-wall water viscosity. In addition, the proposed model is compared and validated with the results from theories and molecular dynamic simulations. Results show that the apparent viscosity decreases with an increasing contact angle, and tends to bulk viscosity with the increase of pore dimension. With contact angle ranging 0 ∼ 180°, the enhancement factor can decrease one order of magnitude with apparent viscosity larger than bulk viscosity, and increase eight orders of magnitude with apparent viscosity smaller than bulk viscosity. With an increasing ratio of semi-long axis a to semi-short axis b of elliptic pores, the apparent viscosity increases first and then decreases down to 0 for a small contact angle, and the enhancement factor decreases first and then increases. In addition, for a larger contact angle, the apparent viscosity gradually decreases and tends to 0, and the enhancement factor increases. The changes of apparent viscosity and enhancement factor are directly related to the changes of boundary velocity and effective viscosity which are caused by the surface wettability, pore dimensions and shapes. The proposed model can be used to describe the liquid flow in nano-scale elliptic pores with different surface wettability, like the shale oil transport in oil-wet organic and water-wet inorganic pores.