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Gas transport in shale matrix is complex due to multiple mechanisms and is difficult to be investigated by macroscopic experiment. For Gas Research Institute (GRI) method, which is the most accepted one for gas transport investigation in shale matrix, the apparatus was modified by adding an automatic gas supplement and pressurization (AGSP) system, and a numerical model considering the variation of real gas property and the Klinkenberg effect was established for data interpretation. Then, the intrinsic permeability and Klinkenberg coefficient were effectively obtained by maintaining high expanding speed of gas in apparatus and eliminating the negative effect of low filling degree of sample. By analysis, the ideal gas transports faster than real gas due to the viscosity difference at low pressure and the deviation factor difference at high pressure. For Wufeng-Longmaxi shale matrix, the positive influence of Klinkenberg effect on gas transport would attenuate with increasing pressure and is more powerful than bulk shale sample with fractures. Therefore, the gas transport in real shale matrix could be well known, which is meaningful to production forecast and evaluation in oil and gas fields.

High-pressure sorption isotherms of CH4, C2H6, and their mixtures on shales from Sichuan Basin, China, were measured by a volumetric method. The sorption measurements for pure components were condu...

The usage of direct current (DC) voltage has enormous potential for oil fields due to the effect of wettability alteration. However, the unclear mechanism of the wettability alteration has limited the application of this technology to oil fields. In this study, chemical and physical methods including contact angle tests, Fourier-transform infrared spectroscopy (FTIR) measurements, and atomic force microscope (AFM) experiments were combined to investigate the wettability alteration mechanism for tight sandstones subjected to DC voltage treatment. From the view of a chemical factor, FTIR results show that DC voltage decreases the number of Si-O-Si, C-O-C, C-O, and COOH groups, while it also increases the number of C═O and OH groups. The changes in molecular groups further improve the water-wetting property of tight sandstones. On the other hand, in a physical way, AFM results indicate that DC voltage improves the roughness of the rock surface. At the same time, the wetting state transfers from the Cassie-Baxter to the Wenzel. This increases the contact area of the solid-liquid interface. The augment of roughness and the transfer of the wetting state improve the water-wetting property of tight sandstones. By comparing the influences of both chemical and physical factors on wettability, it is concluded that although roughness indeed affects the wettability, chemical factors play a dominant role in determining the wettability. Achievements in this study can help researchers and engineers better understand the mechanism of wettability alteration and further accelerate the development of tight sandstones with DC voltage-related technology.

Carbon materials, coal-bed methane and shale gas reservoirs contain various carbon pore geometries like slit and cylinder. Simplified local density (SLD) model is a beneficial and widely recognized method for gas adsorption in slit-like carbon pore, and hasn't been completely extended from slit-like carbon pore to cylindrical carbon pore, which restricts its actual application. Herein, a SLD-cylinder model is established by obtaining the key parameters (i.e. attractive parameter and co-volume parameter in adsorbed phase) with the introduction of dummy attractive potential and the validation with clean energy gas (i.e. H2 and CH4) computational adsorption results. Meanwhile, for this model, the effect of carbon layers and the sphere of application are fully discussed here. Furthermore, based on SLD-cylinder model, isobars and isotherms of H2 and CH4 at a temperature ranging from 213 to 413 K and a pressure ranging from 1 to 10 MPa are investigated in 2.7 nm and 1.35 nm cylindrical pores. We find that carbon layer number is an essential factor for gas adsorption calculation in a cylindrical pore. Also, the SLD-cylinder model is applicable for the pressure higher than ambient one and the pore size larger than 1 nm. Moreover, owing to the significant effect of bulk fluid density (BFD) on excess adsorption, for CH4 especially, the shapes of isobar and excess isotherm vary mightily with pressure and temperature, respectively. This understanding could be applied to the storage of clean energy gas and the recovering of coal-bed methane (CBM) and shale gas. Therefore, the new developed SLD-cylinder model is as useful as the original SLD-slit model in the applications of gas storage, unconventional gas reservoirs recovering and pore structure characterization.

A large percentage of tight oil is trapped underground due to the lack of effective enhanced oil recovery methods. Direct current (DC) voltage flooding has become one of the emerging and promising methods for in situ enhanced oil recovery because of its economic and environmental advantages. Nevertheless, the effect of DC voltage on the enhanced oil recovery for tight sandstone reservoirs is still unclear. In this study, the effects of DC voltage, the concentration of brine water and flooding styles on enhanced oil recovery have been investigated. The experimental results show that there are an optimum DC voltage (∼10V) and an optimum concentration of brine water (∼0.7 mol/L). The oil displacement efficiency with the DC voltage (∼10V) increases by 50% compared with that the oil displacement efficiency of the conventional flooding with 0.1 mol/L sodium chloride. A low concentration of brine water would increase the oil displacement efficiency when the DC voltage is applied, while a high concentration of brine water would reduce the oil displacement efficiency. Moreover, the results of different flooding styles indicate that the sequential flooding obtains more oil than the simultaneous flooding and conventional flooding under the condition of a relatively high concentration of brine water. Several mechanisms of electrokinetics have been revealed in this study. Laboratory experiments indicate that electrokinetic flooding would be a promising enhanced oil recovery technique and needs to be investigated further.

Previous research has confirmed that substantial yield has been recovered in the soaking period after hydraulic fracturing. Spontaneous imbibition (SI) is the primary mechanism responsible for the enhanced oil production and has become an effective oil recovery method with regards to unconventional reservoirs. Despite the importance of SI, an in-depth understanding of the features of SI in tight reservoirs is still inadequate. In this article, nuclear magnetic resonance (NMR) T2 was employed to study the dynamic behavior of imbibition in tight sandstone samples from Yanchang formation, Ordos Basin. Additionally, high-pressure mercury intrusion (HPMI) and the initial T2 of a core sample were combined to characterize pore structures of tight rocks and oil distributions in various pores at different imbibition stages. Then, the effects of gravity, anisotropic pore structure, and non-wetting phase (NWP) viscosity on imbibition recovery were determined via the variations in T2 spectra for each sample. The results show that the tight cores feature a multiscale pore structure. Sub-micropores is the dominant type providing the major contribution to oil recovery, while nanopores have largest imbibition efficiency due to the larger capillary force. Gravity of fluids has a non-trivial effect on SI and cannot be neglected in tight samples under two-ends-open (TEO) or one-end-open (OEO) conditions; this seemingly counterintuitive finding is because the capillary force is weakened by the resistance force caused by the intricate flow paths and other possible surface forces at the nanoscale. Imbibition performance in a tight medium is strongly related to its pore structure. The variations in directional permeabilities, relative permeabilities and capillary pressure functions resulting from highly anisotropic samples greatly affect both the ultimate oil recovery and imbibition rate for tight samples under TEO condition, but only impact imbibition rate under all-faces-open (AFO) condition. Furthermore, because tight oil has a narrow range of viscosity, the imbibition behavior in tight samples may not be sensitive to the oil viscosity. It would be hoped that the insights gained from this study can help to improve our understanding of imbibition characteristics in tight reservoirs and develop new scaling models for the predication of oil recovery.

Kerogen is the source of hydrocarbons in shale. As a soft nanoporous matter, kerogen constantly experiences mechanical deformation induced by subsurface stress environment and interplay with geoflu...

The Simplified Local Density (SLD) model has been widely used to study the adsorption of gases on activated carbon, coal and shale. However, previous studies mainly focused on the experimental data fitting and the adsorption prediction based on model regression parameters. Few studies have been conducted to investigate the fluid distribution in the pores, which is of great significance for the study of the adsorption mechanism. In this study, high pressure adsorption experiments coupled with SLD model were impressed on the study of adsorption characterizations of shales from Sichuan Basin, China. The results showed that the SLD model could fit the adsorption of gas on shale well, and the average absolute deviations were within 10%. The gas was adsorbed around the pore wall when the pore size was large. As the pore size decreased, the gas molecules in the pore center also began to be adsorbed and finally all the gas in the pores were in an adsorbed state when the pore size was decreased to a certain value. According to the adsorption potential energy curves of CH4 and CO2 gas, CO2 was preferentially adsorbed relative to CH4 when the pore size was larger than 0.42 nm, which was consistent with the experimental results; while when the pore size is less than 0.42 nm, CH4 was preferentially adsorbed. This may be due to that in smaller pores, the repulsion of the pores to CO2 was greater than CH4, making it more difficult for CO2 to enter the pores. The adsorbed phase density was a function of temperature, pressure and pore size. The temperature only changed the magnitude of the adsorbed phase density, while the pore size not only changed the magnitude, but also changed the tendency of the adsorbed phase density with pressure. A temperature dependency model was finally established. Adsorption at a wider range of temperatures can be predicted basing on the model.

The main objectives of this study were to investigate the effects of boundary condition and pore size on spontaneous imbibition in tight sandstones, and to simulate and interpret the flow process. In this study, scanning electron microscopy (SEM), mercury injection capillary porosimetry (MICP) and nuclear magnetic resonance (NMR) T2 were combined to investigate the pore systems of the tight sandstone outcrop from Yanchang formation, Ordos Basin. Five parallel sets of imbibition experiments were also carried out, respectively using NMR and imbibition cell to guarantee the reliability of recovery data. Furthermore, a study was conducted to validate the linear model of recovery versus the square root of time in tight sandstones under different boundary conditions. The radial countercurrent flow encounters the linear flow, and causes mutual interference in the late stage of imbibition, which is probably the main reason for a lower recovery of all-face-open (AFO) imbibition than two-ends-closed (TEC) imbibition. Imbibition efficiency decreased with the increase in pore radii around the immovable peak, while it increased with increasing pore radii around the movable peak. The linear relationship between the imbibition recovery and the square root of time was best fitted by TEC imbibition, whereas the relationship in two-ends-open (TEO) imbibition is poor. In addition, different behaviors between TEO imbibition and the other four types indicate that gravity cocurrent flow dominates in the former one.

Based on Zetasizer Nano ZS instrumentation, the zeta potential with Ca2+ and tight oil reservoir were analyzed to study the abilities and microscopic mechanisms on reservoir characteristics of wettability. The results show that in the CaCl2 solution, Ca2+ can reduce the surface hydrophilicity of tight sandstone, thus change the reservoir wetting characteristics. While increasing pH can improve reservoir wettability and facilitate tight oil development. Ca2+ can change the structural characteristics of tight reservoirs and crude oil. This provides a theoretical basis for our study of low salinity water flooding and recovery ratio.

A representative molecular model of shale organic matter (OM) is prerequisite to further theoretic investigation on the fundamental mechanisms governing storage, transport and recovery of shale gas. In this work, a systematic strategy to prepare structural and compositional properties of OM is reported first, and then a realistic molecular model of Chinese Cambrian OM is generated based on analytical experimental data. Microstructure characterization and adsorption simulation are further performed using molecular dynamics simulation and grand canonical Monte Carlo simulations, respectively. The OM model, composed of kerogen macromolecules, bitumen components and residual lighter components, shows a reasonable representation of realistic Cambrian OM with respect to structural parameters, generic compositions, physical density and porosity. The OM porous network consists of dominant ultra-micropores and limited micropores. Compared with heavier components, lighter components are more inclined to occupy accessible pores. Interestingly, lighter components are observed to appear in pairs due to competitive adsorption around heteroatom groups. Water molecules are scattered in the system because of abundant functional groups and poor pore connectivity. The OM skeleton represents the adsorption behaviors of methane, carbon dioxide and nitrogen well. The adsorption capacity is carbon dioxide > methane > nitrogen. A higher adsorption capacity corresponds to a lower pressure when the excess isotherm reaches the maximum. The adsorption behaviors of heavier hydrocarbon species (ethane, propane and n-butane) cannot be represented in the OM skeleton with ultra-micropores and limited micropores, and the effect of molecular sizes of these species cannot be neglected. This work reports a systematic construction process for realistic molecular model of shale OM, and the representative OM model can serve as a starting point to explore gas adsorption and transport mechanism in shale organic pores at microscopic scale.

The flow mechanism of natural gas in the shale matrix is closely related to the high efficient development of shale gas reservoirs. However, the flow characteristic of shale gas in nanometer pores is scale dependent, and is also affected by the formation condition, adsorption layer, residual water saturation and detailed pore structure. In this study, a lattice Boltzmann model with a regularization procedure was applied to simulate shale gas flow in a 2D porous medium, and the effects of slippage, adsorption layer, residual water saturation and surface area on the apparent permeability were discussed. Simulation results indicate that the apparent permeability decreases with the increasing formation pressure, and increases with the increasing formation temperature and characteristic pore size. The adsorption layer and residual water affect the apparent permeability by changing the effective pore space for gas flow. And the effect is more obvious under the large Knudsen number conditions. When the porosity of the porous media is constant, the apparent permeability decreases with the increasing surface area, and the large surface area would even offset the positive effect of slippage on the apparent permeability.

Tight oil sandstones have obscured flow characteristics because of their complex pore structure and ultralow permeability. In this study, representative elementary volume (REV) scale lattice Boltzmann method (LBM) was applied to simulate fluid flow in the multiscale tight porous media generated by coupling digital cores from two scales, and the effects of clay permeability, clay volume fraction and interparticle pores (interP) volume fraction on the permeability of the multiscale tight porous media were analyzed. The tight multiscale porous media were generated by assigning the nanometer scale digital core of clay to each pixel of clay constituent in the micron scale digital cores containing three constituents of matrix, interP and clay. The porosity of the generated multiscale tight porous media ranges from 11.12% to 14.98%, among which the porosity contributed by the interP is 4.06–5.00%, and the porosity contributed by the clay is 6.40–9.98%. The pore size distribution curves are bimodal with the pore size ranging from 0.05 to 100 μm, and show good agreement with our previous experimental results. The porosity and permeability inputted to the REV scale LBM were from pore scale simulation results of fluid flow in the nanometer scale digital cores. The simulated permeability of the multiscale tight porous media is 0.05 × 10−3–0.23 × 10−3 μm2, which is close to our experimental results. The permeability of the multiscale tight porous media shows positive linear correlation with the clay permeability and clay volume fraction, but is unrelated to the interP volume fraction in the reasonable porosity range. It is hoped that this study can provide some new insights into the core analysis of tight oil sandstones.

High pressure sorption isotherms of pure CH4 and CO2 at 80 °C and CH4/CO2 mixtures at 30 and 80 °C on shale samples from Sichuan Basin, China, were measured by a modified volumetric method. The multicomponent sorption measurements were conducted on the mixtures with feed gas compositions of 79.50% and 48.62% CH4. The sorption isotherms of pure CH4 and CO2 were fitted by a modified Langmuir equation, and the sorption isotherms of the total and individual component of CH4/CO2 mixtures were fitted by an extended Langmuir (EL) equation. Qualitative and quantitative characterizations of selective sorption of CH4 and CO2 were discussed at different temperatures and gas compositions. The results indicate that the sorption capacity of pure CO2 is larger than that of pure CH4, with the Langmuir sorption capacity of pure CO2 being approximately 2.5 times of pure CH4. However, a higher sorption amount of CH4 than CO2 is obtained in competitive sorption of mixed gas with a feed gas composition of 79.50% CH4, suggesti...

Based on realistic kerogen model, the effects of water content on methane (CH4) adsorption capacity were studied qualitatively and quantitatively using the molecular dynamics (MD) and Monte Carlo (MC) simulation methods. The methane single component adsorption process under the dry condition, methane and water two components competitive adsorption on dry kerogen, and methane single component adsorption on moist conditions (0.6, 1.2, 1.8, 2.4, and 3.0 wt%) were simulated. Adsorption processes under different temperatures (298, 323, and 348 K) were modeled, and the pressure was up to 20 MPa. Simulation results show that the absolute adsorption capacity of CH4 on the dry kerogen increases with the increasing pressure but decreases with the increasing temperature. The excess adsorption capacity increases up to a specific pressure and then declines with the increasing pressure. The competitive adsorption simulation results indicate that kerogen prefers to adsorb water (H2O) than CH4. At the pressure of 20 MPa and temperature of 298 K, the competitive adsorption capacity of CH4 (0.53 mmol/g) is only a seventh of the single component adsorption capacity of CH4 (3.92 mmol/g) on dry kerogen. The CH4 adsorption capacity on moist kerogen also decreases with the increasing moist content. Compared with the absolute adsorption capacity on the dry kerogen (3.92 mmol/g), the adsorption capacity on the moist kerogen reduces about 16%, 30%, 40%, 47%, and 55% at 20 MPa, respectively. The reduction of the adsorption capacity is attributed to the strong attraction between kerogen and water. At last, the effect of the water content on the shale gas adsorption is discussed under the micro-scale, and the adsorption capacity reduction curves were calculated under the reservoir conditions. The results show that the adsorption capacity of shale gas is significantly affected by water at the economically recoverable depth. The dry condition is considered as the situation of the maximal adsorption capacity of the shale gas reservoir. This study can serve as a reference for better understanding of the transportation and storage mechanism of shale gas under the reservoir conditions.

This paper explores the applicability of nuclear magnetic resonance (NMR) technology on pore size distribution (PSD) and movable fluid distribution (MFD) in tight sandstones. Centrifugation experiments and NMR tests are performed on saturated samples. The fluid changes in pores corresponding with three different types of NMR T2 distribution after each centrifugation is then analyzed. In addition, a new method to determine the conversion factor from NMR T2 distribution to PSD is developed. In comparison with the PSD obtained by mercury intrusion porosimetry, the new method is more suitable for PSD calculation in tight sandstones. Afterward, the optimum centrifugal force to determine the threshold radius for fluid flow is obtained. On the basis of this, we analyze MFD in tight formation. Through study, the following results are arrived at: patterns of NMR T2 distributions of outcrop and subsurface cores at water saturation condition can be classified into three types (I, II, and III). Among which, type I an...

Based on DSA100 instrumentation, the interactions between the chemical groups on the rock surface and brine were analyzed to study the abilities and microscopic mechanisms on reservoir char...

Although research attentions for CO2 injection in gas-bearing reservoirs have been drawn to CO2 sequestration with enhanced gas recovery (CS-EGR), the microscopic competitive adsorption mechanism of methane (CH4) and carbon dioxide (CO2) considering the effect of organic type and moisture remains to be determined. In this work, we focus on the competitive adsorption behaviors of CH4 and CO2 on dry and moist realistic kerogen models of different organic types by performing combined molecular dynamics (MD) and grand canonical Monte Carlo (GCMC) simulations. The effects of organic type and moisture content on kerogen pore structures, moisture distribution and interaction between CH4/CO2 and kerogen surfaces are discussed in details. Simulation results show that CO2/CH4 adsorption capacity and adsorption selectivity are in the order of kerogen IA

The adsorption behaviors of methane (CH 4 ), carbon dioxide (CO 2 ) and their mixtures are vital to understand the process of CO 2 sequestration and shale gas exploitation. In this work, four realistic kerogen models with different maturities (immature (IIA), beginning of oil window (IIB), middle of oil window (IIC), postmature (IID)) were built by the molecular dynamics (MD) method. The adsorption characteristics of CH 4 , CO 2 and their mixtures on these kerogen models with various moisture contents (0, 0.7, 1.4, 2.1, 2.8 wt%) were investigated by the grand canonical Monte Carlo (GCMC) simulations. The influences of kerogen maturity and moisture content on the adsorption capacity, isosteric heat of adsorption and adsorption selectivity of gas molecules were discussed. Simulation results show that the maximum adsorption capacity of gas molecules increases with increasing kerogen maturity, but decreases with increasing moisture content, and the reduction decreases as the maturity increases at high moisture contents. The average isosteric heat of CO 2 adsorption is relevant to the sulfur/oxygen content of kerogen models. The pre-adsorbed water (H 2 O) has a small effect on the gas isosteric adsorption heat when located in the middle of pores, but can reduce the CO 2 isosteric adsorption heat by occupying the hydrophilic groups. Moreover, H 2 O molecules are observed to migrate and aggregate into growing clusters at higher moisture contents for kerogen IIC and IID models, increasing the gas isosteric adsorption heat. The CO 2 /CH 4 adsorption selectivity gradually decreases to the equilibrium value with the rise of bulk pressure. Also, the selectivity decreases with increasing CO 2 mole fraction for lower mature kerogen models (IIA and IIB), but increases with the CO 2 mole fraction at low pressure for kerogen models of higher maturity (IIC and IID). Meanwhile, the selectivity increases for IIA, IIC and IID models, while decreases for IIB model as the moisture content increases. This study gains deep insights into the effect of kerogen maturity and moisture content on the interaction between CH 4 /CO 2 and kerogen at microscopic scale.

Wettability is a deciding attribute in enhance oil recovery research, thus plays a vital role in unconventional reservoir development. Previous studies were focused on wettability modulation of the reservoir rocks by changing the properties of fluids. However, the wettability alteration mechanism of tight sandstones remains unclear. In this study, the influence of molecular groups on wettability is discussed by measuring the contact angle of samples from the Upper Triassic Yanchang Formation after being subjected to the supercritical carbon dioxide-water-rock dynamic reaction. The mineral composition of the samples under different reaction times was characterized by XRD. Zeta potential measurements and the Fourier-transform infrared spectroscopy (FTIR) technique were combined to determine the type and amount of molecular groups on the rock surface. Results show that the sample becomes more hydrophilic with the reaction time because of the varied composition of rock minerals induced by the chemical reaction. However, it is not easy to discern the influence of different mineral content on wettability only through the XRD experiment. The Supercritical carbon dioxide - water - rock dynamic reaction reduced the absolute value of zeta potential and weakened the effect of the electrostatic force on wettability, yet increased the content of hydrophilic groups (C–O and C O), and thus reduced the contact angle (altered the wettability towards more water-wet). This study can advance the understanding of the wettability alteration mechanism in tight sandstones and promote the development of carbon dioxide geologic sequestration and enhanced oil recovery technologies by the regulation of wettability.

The increasing application frequency of direct current (DC) voltage to various aspects has attracted much attention in its potential stimulation for petroleum engineering due to several unique advantages. Related experiments have demonstrated that an electric field improves the oil recovery in tight sandstones. However, regarding whether the variations in the pore structure of tight sandstones after being treated by an electric field exist remain open. In this study, a high-pressure mercury intrusion (HPMI) and a cold-field scanning electron microscopy (CF-SEM) were combined to study the changes in the pore structure after applying an electric field to tight sandstones. The experimental results show that DC voltage opens nanopores ( 1 μm). The electrokinetic effects (electroosmosis and electromigration) facilitate the development and interconnection of micropores, triggering the formation of large micropores and fissures. However, it is worth noting that the sediment flocculation will be produced and block the micropores when a high voltage or a high concentration of solution exceeded the optimum values is employed, resulting in a decrease in oil recovery compared with maximum oil recovery. This accounts for the reason why there are optimal DC voltage and ionic concentration. This gained information can help engineers and researchers understand the evolutions in the pore structure of tight sandstones subjected to DC voltage treatment, which may accelerate the application of DC-related technology for the effective exploitation of tight sandstones.

Methane sorption on organic-rich shales over wide temperature and pressure ranges (30–120 °C, up to 25 MPa) is analyzed by the pore filling/potential theory. The supercritical Dubinin–Astakhov (SDA...

This article applied the multiple relaxation time multicomponent/multiphase pseudopotential lattice Boltzmann model to simulate two immiscible fluids flow in 2D porous media, and analyzed the effects of capillary number (Ca), viscosity ratio (M) and wettability on the relative permeability curves. Simulation results indicate that the nonwetting phase (NWP) relative permeability increases with increasing Ca; while the effect of Ca on the wetting phase (WP) relative permeability depends on the wettability. When M > 1, the NWP relative permeability increase with increasing M in a strong wetting condition because of the lubricating effect. The amplitude of the NWP relative permeability may even exceed the single phase permeability. However, the exact value of the amplitude and where it occurs depends on M and the structure of the porous media. The WP relative permeability is insensitive to M. When the porous media converts from strong wetting condition to neutral wetting condition, the NWP relative permeability decreases while the WP relative permeability increases.

Silurian marine shale in Sichuan Basin is the most significant target zone for shale gas resources in China. In this work, a combined experimental and molecular simulation study was conducted to characterize the thermodynamic and structural properties of the organic matter in Silurian shale. Organic geochemistry experiments and Fourier transform infrared (FTIR) spectroscopy were performed to provide structural parameters for the main skeleton of the organic matter. A realistic molecular model of the organic matter under typical reservoir conditions was generated by molecular dynamics simulations based on the experimental results and documented analytic data. The thermodynamic and structural properties of the organic matter model were discussed in detail. Clear correlations are found among geochemistry properties and structural parameters of organic matter, independent of organic matter type and maturity. Aromatic units in the organic matter are highly condensed, and the interunit linkages are mainly short...

As potential alternative resources, tight oil and gas reservoirs are generally exploited with multistage hydraulic fracturing technology to meet the rising demand for energy in the world. Considerable production recovered by the infiltration of fracturing fluids into the rock matrix shows that spontaneous imbibition (SI) is an effective oil recovery method. Through the use of Nuclear Magnetic Resonance (NMR) detection technique, the features of SI in oil-water and gas-water systems for tight sandstones were studied. The T2 spectra of these samples were used to reflect the migration patterns of fluids in various pores under different imbibition systems. In addition, the impacts of the boundary conditions on imbibition outcomes were also determined via the variations in T2 spectra under imbibition stages. The results indicate that tight sandstone samples display the feature of complex pore structure with a wide range of pore size distribution, and the dominant types are micropores and small mesopores. With the progression of imbibition experiments, oil in micropores will be more easily displaced by wetting fluid and flow out through interconnected smaller pores due to greater capillary pressure. The majority of the production through imbibition can be attributed to the contribution made by the micropores. However, water could not enter the mesopores readily under the gas-water system if it is only driven by capillary pressure owing to the snap-off effect of gas. The boundary conditions have notable effects on the imbibition rate and ultimate recovery for the oil-water system and increasing the areas available for water imbibition helps to maintain higher imbibition rate and recovery. However, regarding the gas-water system, boundary conditions have little influence on the imbibition recovery but have a remarkable influence on the imbibition rate. The traditional scaling equations used to scale the imbibition data for both the oil-water and gas-water systems and predict imbibition recovery is acceptable if the wettability of the tight medium remains unchanged. This research aims to uncover the imbibition characteristics of fluids and the nontrivial effect of boundary conditions in tight sandstone samples, which would contribute to the successful development of tight formations.

Water transport at the nanoscale is a significant phenomenon related to unconventional hydrocarbon production. This study develops a new model of the lattice Boltzmann method to simulate the nanoconfined water transport through a rough pore. The proposed model considers the interface viscosity and the slip length according to the surface wettability. Water flow simulations are conducted to analyze the flow characteristics and the transport capacity under various wettability and surface roughness conditions. Results show that the fluid velocity and pressure distributions along the flow direction are profoundly affected by the rough surface. As the contact angle increases, the transport capacity has a minor increase in the hydrophilic condition, but a significant rise in the hydrophobic state. Also, with the increase of relative surface roughness, the transport capacity for the hydrophobic rough nanopore is greatly enhanced, while for the hydrophilic pores, only a minor variation is observed. The dimensionless liquid permeability gradually decreases as the relative surface roughness increases irrespective of the wettability. However, the fractal dimension of the rough surface rarely affects both the transport ability and the dimensionless permeability. Finally, this study presents an empirical permeability estimation model for rough nanopores.

Summary This work presents an analytical solution for the pseudosteady-state (PSS) flow in a hydraulically fractured stratified reservoir with finite fracture conductivity in the presence of interlayer crossflows. Specifically, a three-layer configuration is considered, with the midlayer hydraulically fractured and sandwiched between two adjacent layers feeding the midlayer by crossflows. The circular drainage area is approximated as elliptical, allowing the problem to be solved in elliptical coordinates analytically. Explicit expressions in the physical-variable space for the dimensionless productivity index (PI) and the wellbore-pressure drawdown for the PSS flow of such a hydraulically fractured system with interlayer crossflows are derived for the first time. Compared with the case without interlayer crossflows, the dimensionless PI is reduced because of additional pressure drawdown occurring in the sandwiching layers; on the other hand, the time rate of increase of the pressure drawdown at the wellbore is also decreased because of the addition of the producible fluid stored in the sandwiching layers. This slower time rate of increase of the wellbore-pressure drawdown prolongs the PSS production period, which can lead to a larger accumulative production. It is also shown that when the layers have comparable thickness, fracturing the higher-permeability layer provides the best performance because the wellbore-pressure drawdown experiences the slowest time rate of increase during the PSS flow period. The analytical solution can also be used for fracture-design optimization as well as production-decline analysis for fractured stratified systems.

High-pressure methane sorption isotherms were collected on selected Paleozoic shales from the Sichuan Basin. Excess sorption measurements were performed on shales with varied water content (dry, moisture equilibrated at 33%, 53%, 75%, and 97% relative humidities) at 39 °C and up to 25 MPa. Water uptake isotherms were collected at 24 °C and parametrized by the Guggenheim–Anderson–de Boer (GAB) model. The effect of organic richness, mineral compositions, and pore structure characteristics on water uptake and methane sorption behavior has been investigated. The mechanism responsible for the decrease in methane sorption capacity of moisture-equilibrated shales is discussed. Water uptake of shales is primarily controlled by clay minerals, and shows a positive correlation with clay mineral content. Water sorption isotherms of shales can be approximately expressed as the sum of the isotherms of individual clay minerals on a mass-fraction base. Methane sorption capacity of these shales is controlled by TOC conten...

This paper aims to analyze the effects of mineralogy on petrophysical properties and evaluate the performance of eight permeability estimation models in tight oil sandstones. The results include mineralogy, pore size distribution, porosity, and permeability. The evaluated eight permeability models are Purcell, Winalnd, Swanson, Thomeer, Wells-Amaefule (W-A), Katz-Thompson (K-T), Pittman and Dastidar models. The experimental results indicate that the samples are rich in quartz (averages 41.5%), feldspar (30.0%), and clays (18.5%); have a wide pore size distribution mainly in the nanometer scale (9.2 nm–1 μm); and have low porosity (11.07% on average) and ultralow permeability (0.22 mD). Quartz and feldspar preserve the primary pores by supporting the overburden pressure, and feldspar further enhances the porosity by forming secondary dissolution pores. Mixed layer of illite/smectite (I/S) and illite significantly decrease porosity while chlorite preserves the primary pores by inhibiting silica overgrowth. The Pittman model has the best estimation accuracy ( R adj 2 = 0.968); the Winland, K-T and Dastidar models give reasonable estimations ( R adj 2 > 0.92); others have poor performance ( R adj 2

Silurian shale in Sichuan Basin is currently the most important target zone for shale gas exploration and development in China. Pore structure characteristics of Lower Silurian Longmaxi shales from southern Sichuan Basin were investigated. The combination of field emission scanning electron microscope (FE–SEM) and argon ion beam milling was utilized to describe the nanometer-to micrometer-scale (> 1.2 nm) pore systems. The shales were characterized by organic geochemical and mineralogical analyses. Total porosity, pore size distribution (PSD), specific surface area, and gas content were determined. Controls of organic matter richness, thermal maturity, and mineralogy on porosity were examined. The contribution of individual mineral components to total porosity was analyzed quantitatively. Total gas contents of the shales determined from canister desorption data were compared with theoretical (sorptive and volumetric) gas storage capacities. The total organic carbon (TOC) content of the shale samples ranges between 0.1 and 8.0 wt.% and helium porosity varies between 0.7 and 5.7%. Maturity in terms of equivalent vitrinite reflectance of bitumen (Reqv) ranges from 1.8 to 3.2%. TOC content is a strong control for the pore system of these shales, and shows a positive correlation with porosity. Porosity increases with increasing thermal maturity when Reqv is less than 2.5%, but decreases for higher thermal maturity samples. FE–SEM reveals four pore types related to the rock matrix that are classified as follows: organic matter (OM)–hosted pores, pores in clay minerals, pores of framework minerals, and intragranular pores in microfossils. Pores in clay minerals are always associated with the framework of clay flakes, and develop around rigid mineral grains because the pressure shadows of mineral grains prevent pores from collapsing. Pores of framework minerals are probably related to dissolution by acidic fluids, and the dissolution–related pores promote porosity of shales. A unimodal PSD exists in the micropore range of TOC–rich samples, while the PSD of carbonate–rich samples are bimodal. A PSD maximum in the micropore range is attributed by OM and another maximum in the range of mesopore–macropores is probably caused by the dissolution of carbonate minerals. Quantitative evaluation of the contribution of individual mineral components to porosity shows that the organic matter contributes approximately 62% to the total porosity. Framework minerals (quartz, feldspar, and carbonates, et al.) and clay minerals contribute 25% and 13%, respectively. The total gas content of these shales ranges from 0.4 to 6.2 m3/t, and the total gas contents of selected samples determined from canister desorption tests agree with the theoretically estimated original gas-in-place (OGIP). OM-hosted pores are the main space for gas storage, and accounted for about 78% (55% adsorbed gas plus 23% free gas) of the OGIP, while pores in the inorganic matter accommodate 22% free gas of the OGIP.

This paper aims to interpret the low-velocity nonlinear flow occurring in low-permeability reservoirs based on the theories of electrokinetic transport and non-Newtonian rheology of fluids. To achieve this end, we simulate the steady-state electroviscous flow of Bingham-Papanastasiou (BP) fluids in circular microtubes by simultaneously solving the Poisson-Boltzmann and the modified Navier-Stokes equations. The induced electrical field strength E s , velocity profiles, and the transport capacity of the non-Newtonian fluid under the effects of various factors (such as capillary radius R, zeta potential ζ, yield stress τ0, and stress growth index m) were examined. The results show that the generated E s of the BP fluid is highly affected by the fluid rheology, which is quite different from that of the Newtonian liquid. The velocity profiles become lower and flatter as m or τ0 increases, and this is more remarkable in smaller microtubes. The apparent viscosity of non-Newtonian fluid declines monotonically with increasing c∞, yet non-monotonically with R, m, τ0, and ζ. In addition, the low-velocity nonlinear flow in microtubes can be successfully captured when considering the electrokinetic flow of the non-Newtonian fluid rheology. While for the Newtonian fluid, only involving the electroviscous effect fails to generate the nonlinear flow behavior. The contributions of electrokinetic parameters versus rheological properties to the degree of flow nonlinearity are also discussed. The impact of electrokinetic parameters (ζ, c∞) on the flow characteristics is significant at high-pressure gradients and becomes trivial when the pressure gradient is relatively low. In contrast, the fluid rheological parameters (m, τ0) greatly determine the magnitude of the flow nonlinearity occurring at the low-pressure gradients. In sum, the electroviscous flow of BP fluids in microchannels provides a possible explanation of the low-velocity non-Darcy flow in porous media.

T2 cutoff is a key representative parameter of rock pore structure, which can reflect the degree of mobile fluid as a function of variable water saturation controlled by the extent of centrifuging. However, few studies of T2 cutoff have been done on tight sandstones. In this study, residual fluid of samples after a series of centrifuges were scanned by NMR to determine T2 cutoffs (the relaxation time separating mobile from immobile water) and the extent of mobile fluid as a function of variable water saturation controlled by the extent of centrifuging. Results indicate that all reservoir cores exhibit bimodal NMR T2 distributions, while outcrop cores mainly show unimodal NMR T2 distributions. Tight sandstones showlittle or no mobile fluid controlled by pore throats with radii ≥1 μm, including outcrops and reservoir samples. In conclusion, T2 cutoffs of cores with bimodal NMR T2 distributions and the ones with unimodal NMR T2 distributions were obtained,respectively,at 418 psi and 208 psi, while the former cores exhibit larger T2 cutoffs than the later ones. The critical mobile pore radius for outcrop samples exhibiting a unimodal spectral NMR T2 distribution is 100 nm, whereas the critical pore radius of 50 nm is identified for reservoir samples which display a bimodal T2 distribution. T2gm (The geometric means of T2 fluid distribution at 100% saturation) may propagate error when applying the Schlumberger Doll Research (SDR) model to tight sandstones, whereas T2wa (the weighted average NMR T2 values for the mobile fluid distribution) shows promise as a parameter to predict pore connectivity.

The microstructure characteristics of the reservoir are closely related to the seepage capacity of the reservoir. Compared with conventional reservoirs and low permeability reservoirs, the tight oil is stored in a smaller nanoporous space. The microscopic pore structure of reservoir is the geometrical shape, size, distribution, and interconnected relationship of porosity and throat. The experiment was conducted on several tight rock samples taken from the Chang 7 formation in Xunyi county of Ordos Basin, China. Based on nano-CT scanning and advanced image processing technology Avizo, we build a three-dimensional comprehensive pore and throat network model. In the result of our study, reservoir space types are dissolution pores with mineral particles inside in the pore network model. Then, the pore throat morphology in the forms of small globular and tubular with SEM was explained. There is a big difference in quantity distribution at different locations, which is limited to the permeability of samples. Pore types are mostly round tubular and long tubular, while isolated pores account for a significant proportion. Through making and analyzing the three-dimensional structure of interconnected pores, obtained their specific forms and the division of connectivity types.

Injection of CO2 into shale reservoir is regarded as one potential scenario for CO2 sequestration and enhanced gas recovery (CS-EGR). In this work, a realistic molecular model of kerogen in Chinese Silurian marine black shale was generated using molecular dynamics (MD) simulations. The competitive adsorption of CH4 and CO2 was simulated by the grand canonical Monte Carlo (GCMC) method under different reservoir pressures, temperatures, geological depths, CO2 mole ratios, and moisture contents of kerogen model. Results show that CO2/CH4 adsorption selectivity decreases with increasing reservoir pressure, indicating that CS-EGR can be more efficient if CO2 injection is conducted at the late development stage. The temperature has a negative effect on the selectivity, which indicates that thermal stimulation has an adverse effect on the efficiency of CS-EGR. Also, the selectivity decreases with increasing geological depth, suggesting that shallow shale formations are more suitable for CS-EGR. At low pressures, the selectivity increases with increasing CO2 mole ratio, while at high pressures, the selectivity decreases with the increase of CO2 mole ratio. This result suggests that CO2 mole ratio should be dynamically adjusted with the production so as to adapt to the changing reservoir pressure. At higher pressure condition, both the amounts of CO2 sequestration and CH4 desorption increase with the increase of CO2 mole fraction. However, the adsorption stability of CO2 weakens with increasing injection amounts of CO2. Moreover, the adsorption selectivity decreases initially, and then increases with the moisture content of kerogen. Thus, the performance of CS-EGR may be improved by increasing the kerogen moisture content for Silurian shale gas reservoirs. This study gains enhanced insights on the effect of reservoir pressure, temperature, geological depth, CO2 mole ratio, and kerogen moisture content on CO2/CH4 competitive adsorption, and the results can provide applicable guidances for CS-EGR in shale gas reservoirs.

Knowledge of pore structure and adsorption capacity provides guidance for better studying the origin, hydrocarbon distribution, and productivity of shale gas reservoir. In this study, pore structure characteristics of six shale core plugs with different maturity from the Lower Silurian Longmaxi formation in south China were investigated using the Rock-eval analysis, X-ray diffraction, total organic carbon (TOC) content test, and scanning electron microscope (SEM) observation. To further investigate the influence of maturity, the adsorption behavior of gas shale was experimentally measured, with the maximal pressure being 20 MPa. Rock-eval analysis indicates that Ro is 0.67~1.34%. SEM results show that organic matter (OM) pores are abundant in high-maturity shale sample. The OM pores are mainly irregular to elliptical in shape, the size is 8~100 nm. The TOC content is 0.16~4.21% and shows a positive correlation with the BET surface area. A negative relationship exists between TOC content and average pore diameter, which indicates that abundant nanometer pores are related to the OM. A noticeable characteristic in the pore size distribution curve is that the content of micropores (pore width

Multistage fractured horizontal wells (MFHWs) have become the main technology for shale gas exploration. However, the existing models have neglected the percolation mechanism in nanopores of organic matter and failed to consider the differences among the reservoir properties in different areas. On that account, in this study, a modified apparent permeability model was proposed describing gas flow in shale gas reservoirs by integrating bulk gas flow in nanopores and gas desorption from nanopores. The apparent permeability was introduced into the macroseepage model to establish a dynamic pressure analysis model for MFHWs dual-porosity formations. The Laplace transformation and the regular perturbation method were used to obtain an analytical solution. The influences of fracture half-length, fracture permeability, Langmuir volume, matrix radius, matrix permeability, and induced fracture permeability on pressure and production were discussed. Results show that fracture half-length, fracture permeability, and induced fracture permeability exert a significant influence on production. A larger Langmuir volume results in a smaller pressure and pressure derivative. An increase in matrix permeability increases the production rate. Besides, this model fits the actual field data relatively well. It has a reliable theoretical foundation and can preferably describe the dynamic changes of pressure in the exploration process.

Injection of CO2 into shale plays has been considered as one potential scenario for CO2 sequestration with enhanced CH4 recovery (CS-EGR). In this work, a realistic molecular model of bulk kerogen was constructed by molecular dynamics simulations (MD). Grand canonical Monte Carlo simulations (GCMC) were performed to investigate the replacement of CH4 by CO2 under different reservoir pressures, CO2 mole ratios and kerogen moisture contents. The radial distribution functions (RDF) were computed to discuss the affinity between CH4/CO2 and atoms in the kerogen. Also, the CO2/CH4 adsorption selectivity was computed to evaluate the preferential adsorption of CO2 and CH4. Results show that the CO2/CH4 selectivity increases at the beginning, and then decreases with further increasing pressure, which indicates that low reservoir pressure is beneficial to the efficiency improvement of CS-EGR. The amount of CO2 sequestration and CH4 desorption increases, while the CO2/CH4 selectivity decreases as the CO2 mole ratio increases, indicating the adsorption stability of sequestrated CO2 weakens with increasing CO2 mole ratio. The CO2/CH4 adsorption selectivity decreases initially, and then increases with the kerogen moisture content. Increasing the reservoir moisture content can improve the performance of CS-EGR. The preferential adsorption sites for CH4 are the sulfur-containing groups, while these for CO2 are the nitrogen- and oxygen-containing groups. One adsorption layer is observed for CH4, while two adsorption layers are identified for CO2. This study gains enhanced insights on the replacement exploitation of shale gas by CO2 at molecular scale, and it can provide applicable guidelines for the optimization of CS-EGR in shale gas reservoir.

The matrix of shale gas reservoirs has an extremely low permeability; therefore, fractured vertical wells and multi-stage fractured horizontal wells (MFHWs) are adopted in most cases for exploration purpose. In this context, studying the dynamic pressure in MFHWs in shale gas reservoirs not only provides an important means of obtaining the parameters of shale reservoirs, but also constitutes the basis of evaluating the productivity of shale gas wells. However, existing models for fractured horizontal wells have neglected the heterogeneity of shale gas reservoirs and the seepage mechanism in the nanopores of shale organic matter, and failed to take into account the differences among different occurrence spaces in gas flow characteristics. On that account, in this study, we combined dust gas model (DGM) and generalized Maxwell-Stefan model (GMS) to calculate the apparent permeability considering viscous flow, Knudsen diffusion, surface diffusion and desorption, and introduced these into the macro seepage model to establish a dynamic pressure analysis model considering reservoir heterogeneity and stress sensitivity effect of MFHWs in shale gas reservoirs. Based on the five-linear flow model, this study divides one reservoir into two top reservoir regions, two inner reservoir regions, two outer reservoir regions, and one artificial fracture region. Through analyzing the flow characteristics of different regions, it uses Laplace transformation and regular perturbation methods to solve the model; based on the analytical solution to this model, it plots the dynamic pressure curve and the dynamic productivity curve and carries out flow region division and sensitivity analysis. As indicated by the study results, the model established in this study fits relatively well with actual production data, has a reliable theoretical foundation, and can preferably describe the dynamic changes of pressure in the exploration process of shale gas wells.

The low permeability of kerogen governs the storage and production of shale gas. The flexible kerogen constantly experiences mechanical deformation induced by reservoir environment and complex interplay with geofluids. However, the kerogen deformation associated with CH4/CO2 competitive sorption remains poorly understood. In this work, the effect of preloaded moisture on the deformation of kerogen with different organic types was investigated with molecular dynamics simulation. The kerogen deformation upon CH4/CO2 competitive sorption was quantified with the combination of grand canonical Monte Carlo simulations and poromechanics theory. The effects of various factors and their corresponding contributions were discussed in detail. The effects of kerogen deformation on CH4/CO2 diffusion were studied. Some implications for CO2 sequestration and enhanced gas recovery (CS-EGR) were proposed. Our results verify the theoretical feasibility of CS-EGR in shale gas reservoir. CO2 is observed to have a higher affinity with kerogen and a lower diffusion coefficient compared with CH4, facilitating it to replace CH4 and retain in the kerogen matrix. The rising CO2 composition can induce larger kerogen swelling, thus opening fluid flow pathways and increasing shale gas production. There are optimum moisture content and reservoir pressure corresponding to the maximum effective pore size in kerogen. It could be feasible to enhance the efficiency of CS-EGR by manipulating the reservoir moisture and CO2 injection timing. Thermal stimulation in deep shale reservoir may not be efficient for CS-EGR. CH4/CO2 competitive sorption can induce significant swelling of kerogen. The flexible nature of kerogen should be considered to improve the evaluation on both gas-in-place and CO2 storage capacity.

In this paper, the nuclear magnetic resonance (NMR) technique is applied to exploring the spontaneous imbibition mechanism in tight sandstones under all face open (AFO) boundary conditions, which will benefit a better understanding of spontaneous imbibition during the development of oil & gas in tight formations. The advantages of nuclear magnetic resonance imaging (NMRI) and NMR T2 are used to define the distribution of remaining oil, evaluate the effect of micro structures on imbibition and predict imbibition recovery. NMR T2 results show that pore size distributions around two peaks are not only the main oil distributions under saturated condition but also fall within the main imbibition distributions range. Spontaneous imbibition mainly occurs in the first 6 h and then slows down and even ceases. The oil signals in tiny pores stabilize during the early stage of imbibition while the oil signal in large pores keeps fluctuating during the late stage of imbibition. NMRI results demonstrate that spontaneous imbibition is a replacement process starting slowly from the boundaries to the center under AFO and ending with oil-water mixing. Furthermore, the wetting phase can invade the whole core in the first 6 h, which is identical with the main period of imbibition occurring according to NMR T2 results. Factors influencing the history of oil distribution and saturation differ at different periods, while it is dominated by capillary imbibition at the early stage and allocated by diffusion at later time. Two imbibition recovery curves calculated by NMRI and NMR T2 are basically consistent, while there still exists some deviations between them as a result of the resolutions of NMRI and NMR T2. In addition, the heterogeneity of pore size distributions in the two samples aggravates this discrepancy. The work in this paper should prove of great help to better understand the process of the spontaneous imbibition, not only at the macroscopic level but also at the microscopic level, which is significant for oil/gas recovery in tight formations.