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Summary Waterflooding will induce the opening and extension of fractures, which will create some water flow channels. Due to fracture multiclosures, the obtained fracture half-length from conventional finite-conductivity models is less than the actual value, leading to water flow channels that have been formed but not detected by engineers. According to a large number of waterflooding-front matching schematics and interwell connection coefficient analyses, we find that waterflooding usually connects natural fractures to form bi-induced fractures, which will close nonsimultaneously during the falloff test. In this paper, we develop a waterflooding-induced nonsimultaneously closed multistorage fracture model (WNMF) to describe waterflooding-induced fracture characteristics accurately. The bi-induced fractures are separated into multiple segments to calculate their pressure response. The closed induced-fracture conductivities are constant, and the opened induced-fracture conductivities follow the exponential equation measured by the experiments. Induced-fracture interference and multistorage effects are considered. Finally, the Duhamel principle is used to characterize the storage effects of bi-induced fractures and the wellbore. Results show that the type curve of the WNMF model has bi-peaks on the pressure derivative curve, which was regarded as error data in the past. Closed induced-fracture half-length is identified quantitatively. We can obtain an induced-fracture angle by matching the interference flow (an innovative flow regime in this paper), which can guide engineers to prevent and monitor water breakthrough in time. Using the obtained parameters (induced-fracture angle and closed induced-fracture half-length) can guide well pattern encryption and reasonable well location determination. If the induced-fracture angle is 90°, an additional horizontal line will be shown on the pressure derivative curve. When the horizontal line is misidentified as a quasiradial flow regime, the obtained reservoir permeability will be amplified many times. The multistorage coefficient is obtained to correct the magnified storage coefficient. Equation calculation and model matching methods verify each other to improve closed induced-fracture half-length accuracy. In conclusion, the experiment and mathematical model methods work together to describe the pressure response behavior of water injection wells. The WNMF model is compared with the conventional finite-conductivity model to verify its accuracy. A field case demonstrates its practicality.

Summary Liquid loading seriously affects gas wells production and even causes gas wells abandonment. Many researchers still focus on correcting a critical liquid-loading flow rate to alleviate these problems. However, they still cannot reasonably be explained. Gas flow rate is higher than the critical liquid-loading flow rate, but liquid loading can still occur. Therefore, until an accurate critical fluid-loading flow rate is discovered, we should monitor the fluid-loading phenomenon to prevent it from affecting production gas wells’ performance. In this work, a fracture liquid-loading monitoring (FLLM) model is proposed and solved for the timely monitoring of fracture liquid-loading (FLL) positions and volume. The Newman product and Green function methods are used to develop and solve the FLLM model. The fracture is discretized into 2nxnz grids to describe an FLL volume and position. The numerical simulation method is used to verify the accuracy of the FLLM model. As a result, four innovative flow regimes, including fracture cavity liquid-loading flow, fracture root liquid-loading flow, transitional flow considering fracture cavity liquid-loading flow, and transitional flow considering fracture root liquid-loading flow, are identified on the pressure response curves. The pressure response of the same gas well at different times is well matched by the model in this paper, and the obtained parameters are more reasonable. The FLLM model can correct for magnified permeability, shortened half-length, and magnified wellbore storage coefficient. In conclusion, the FLLM model is established to monitor FLL, and alert engineers to remove liquid loading on time to prevent water from suddenly rushing into a wellbore and causing gas wells abandonment.

Summary It is well known that waterflooding will create fractures. The created fractures are divided into hydraulic fractures (artificial fractures with proppant) and induced fractures (formed during waterflooding without proppant). There is no proppant in the induced fracture, so it will close as the pressure decreases and extend as the pressure increases. We call it a dynamic induced fracture (DIF). Because of reduced pressure, the DIF will be closed during the shut-in pressure test (well testing). The current conventional well-testing model cannot describe the dynamic behavior of the DIF, resulting in obtaining unreasonable parameters. Thus, this work proposes a DIF model to characterize the DIF behavior during well testing (the injection well will shut in, resulting in a reduction in bottomhole pressure and induced-fracture closure). It is worth noting that a high-permeability zone (HPZ) will be formed by long-time waterflooding and particle transport. The HPZ radius will be greater than or equal to the DIF half-length because the waterflooding pressure can move particles but not necessarily expand the fracture. The point source function method and Duhamel principle are used to obtain the bottomhole pressure response. Numerical simulation methods are used to verify the accuracy of the model. Field cases are matched to demonstrate the practicability of the DIF model. Results show a straight line with a slope greater than the unit, a peak, a straight line with a slope less than one-half, and an upturned straight line on the pressure derivative curve. This peak can move up, down, left, and right to characterize the induced fracture’s dynamic conductivity (DC). The straight line with a slope greater than the unit can illustrate a fracture storage effect. The straight line with a slope less than one-half can describe the closed induced-fracture (CIF) half-length. The upturned straight line can describe the HPZ and reservoir permeability. The obtained parameters will be inaccurate if they are incorrectly identified as other flow regimes. Field cases are matched well to illustrate that identifying the three innovative flow regimes can improve the parameters’ accuracy. In conclusion, the proposed model can characterize the dynamic behavior of induced fracture, better match the field data, and obtain more reasonable reservoir parameters. Finally, two field cases in tight reservoir are discussed to prove its practicality.

Summary The color-gradient lattice Boltzmann (LB) method is used to investigate the inertial effect on oil/water countercurrent imbibition characteristics in a matrix-fracture system. The interplay between capillarity, fluid inertia, and viscous force during the imbibition under different viscosity ratios is delineated. Pore-scale dynamics, the interfacial front morphology, and oil recovery under the influence of fluid inertia are also elucidated. Additionally, we study the energy conversion during the imbibition displacement from the perspective of energy balance. Finally, the application of the theoretical scaling model is discussed based on the simulated data. Results show that the pore-scale events involved mainly consist of cooperative pore filling, oil expelled from large pores, and the motion of jetting-like oil clusters under high viscosity ratios. The curve of pressure difference between the fracture inlet and outlet vs. imbibition time can be regarded as a signal to discern the imbibition regime, which is taken together with the energy conversion analysis could further determine how capillarity, external pressure, and viscous dissipation contribute to water imbibition. Capillary force dominates in the cases of low viscosity ratios, and the majority of the surface energy is dissipated. The external pressure becomes increasingly significant and even governs the countercurrent imbibition as the viscosity ratio increases. Furthermore, the oil recovery, interfacial area, and fractal dimension of the nonwetting phase strongly rely on the Ohnesorge (Oh) number when the viscosity ratio is low. In contrast, the inertial effect can be neglected in the cases of high viscosity ratios. Besides, the relationship between the simulated imbibition recovery and imbibition time follows the theoretical scaling model as the external pressure is trivial. The comparable exponents fitted from different Oh numbers reveal that the inertial effect does not alter the imbibition dynamics. In sum, fluid inertia only affects the local fluid behaviors and thus the imbibition oil recovery when the viscosity ratio is low. These results could provide important implications for a range of energy-related and environmental applications, such as the evaluation of fracturing fluids loss, oil recovery by water huff n puff, microfluidic devices, and hydrological sciences.

The electric field method proved in the lab and oil fields is an effective and fast way to significantly improve oil recovery, which can be applied to greatly realize the urgent-need requirements for energy, especially in tight sandstones. Generally, the changed molecular groups treated with an electric field modulate the wettability of reservoirs, affecting the final oil recovery. Herein, the investigation of the impact of the electric field on the molecular groups of reservoirs is imperative and meaningful. In this paper, tight sandstones were placed into a particular instrument and subjected to various strengths of the electric field. Nine treated powders and one untreated powder of tight sandstones were processed by Fourier transform infrared spectroscopy (FTIR) and X-ray photoelectron spectroscopy (XPS) experiments. FTIR results show that the electric field decreases aromatic groups, C-O groups, COOH groups, and aliphatic groups, whereas it increases C=C groups, C=O groups, and OH groups. Interestingly, the changes in C-O groups, C=O groups, COOH groups, and OH groups are all the competitive results of production and consumption during the treatment process. With regard to C-O groups and COOH groups, the consumption has an advantage over the production on the content of functional groups, and the situations for C==O groups and OH groups exhibit a contrary trend. The fitted result of XPS proves the fact that the electric field improves C=O groups, OH groups, and COOR groups, whereas it reduces C-O groups, supporting that the molecular groups can be mutually transformed during the electric field treatment. The obtained knowledge is beneficial to the study of electric field-related technologies on the molecular groups of reservoirs.

It is well known that waterflooding will induce fractures. The extensive direction, length, and conductivity of the induced fractures will largely determine the performance of producing wells. The quantitative characterization of the fractures can help prevent water breakthrough in time. This paper proposes the waterflooding-induced dynamic fracture model (WIDF) to monitor the fracture half-length at any time and extend the stable production period. The rock mechanics principles are applied to characterize the dynamic extension and closure of fractures during water injection and build-up periods. The model was solved using the point source function approach. The phenomenon of multi-dynamic closure causes the fluid to be squeezed several times, creating a storage effect and a non-constant conductivity within the fracture. Experimental results show that the conductivity of water injection-induced fracture follows an exponential function. Finally, Duhamel's principle was used to couple the pressure response of the wellbore and the fracture. The field case is shown in the paper to verify the accuracy and practicality of the WIDF model. Multi-peak appears in the pressure derivative curves. The actual data match well, and the parameter values obtained are close to the actual values. However, the conventional finite-conductivity model treats pressure response data with multiple peaks as incorrect values. This behavior will result in the length of dynamic closed fracture being ignored and the interpreted fracture half-length being smaller than the actual value. Misidentification of fracture lengths will affect the determination of reasonable injection volumes and even cause producing water early, which can severely impact the performance of production wells. The storage effect caused by multiple dynamic fracture closures reasonably explains the significant storage effect obtained by the conventional model. The WIDF model enables researchers can monitor induced fracture half-length at any time, allowing them to take measures in time. The model has been successfully applied to the X oilfield in China and has significantly improved the performance of injection wells and increased the stable production period of production wells. The fluid compressed by dynamic fractures reasonably explains the significant storage effect in injection wells. The identification and interpretation of multiple dynamic fracture closure phenomenon make us obtain more accurate fracture half-length parameters, which monitors and suppresses the occurrence of water breakthrough effectively and help researchers take measures to increase the stable production period of production wells.

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.

In lots of reports, improvement of shale percolation ability by shale-hydration has been reported, some researchers even regard low hydraulic fluid flowback rate as an advantage; they mainly focused on inorganic pores and fractures because brittleness of inorganic minerals decides the fracturing effects, but organic pores occupy large proportion of shale pores. In order to discover the moisture influence on organic pores, we prepare 4 samples by adjusting water content reaching 9.37%, 35.97%, 61.6%, and 80.45% and observe and quantitatively analyze 10,343 pore changes before and after processing of the 4 samples through SEM and image processing software, respectively, meanwhile, match the incremental water invasion rate curve with the dry pore size distribution curve. We also compare the water invasion mass of normal shale sample and organic partially removed sample. This paper first visually observes and counts the influence of hydration on organic shale pores through analysis of pore number, diameter, kurtosis, median, area, and characteristic lengths; discovers hydration and dehydration jointly cause the expected changes; the whole procedure contains two opposite mechanisms, pore closure or deformation caused by squeeze and enlarged pores or newborn fractures caused by water flush. Based on experimental and analysis results, conclusions are drawn that organic pores can be influenced by moisture, water flush and clay hydration expansion work jointly, and water flush function is weak when moisture is low, but it becomes stronger with the sufficient moisture. Therefore, sufficient soak time is beneficial to development.

In order to estimate relative permeabilities of brine–gas, a semi-analytical model based on fractal theory is proposed. The model simplifies porous media as treelike nanotubes, the single nanotube’s flow has been branched out into whole pore network of core sample through treelike fractal theory. Two-phase flow description in sole nanotube, based on a setting of gas bubbles pushing continuous water phase ahead, solves pressure drop around brine and gas bubbles by Stokes’ viscous force, Laplace equation and Fairbrother–Stubbs bubble film thickness formula, Bretherton bubble pressure drop. By substituting the other three classic formulas into Bretherton expression, the iteration equation of pressure drop around a single gas bubble is acquired, the number of gas bubbles is multiplied and the gas phase pressure drop is calculated. Through merging small bubbles into a large bubble, the relative permeabilities of two phases can be solved by introducing Poiseuille’s law and Darcy’s law. After getting the fundamental data, pore size distribution data and viscosity of two phases, relative permeability curves can be drawn, revealing comprehensive elements including wettability, fluid viscosity, saturation, morphological characteristics. The calculated curves cross each other on the right half of the [Formula: see text]-axis, meet the features of real production, flowback difficulties of hydraulic liquid and well production dropping quickly, also show identical trend with experimental data. Through a series of sensitivity analysis, to some extent, the influence on relative permeabilities is compared of different fractal models, different film thickness, bubble length, water sorption layer thickness, elastic deformation of pores.

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...

Tight oil sandstones have complex pore structure due to multiple pore types and multiscale pore size ranging from several nanometers to dozens of microns. In this study, petrophyiscal properties of tight oil sandstones were quantified based on microscale X-ray computed tomography (μXCT) imaging techniques. The pore types in gray scale images were identified; porosity, pore size distribution (PSD), and pore connectivity were analyzed from segmented image stacks; and their permeability was calculated by representative elementary volume (REV) scale lattice Boltzmann method (LBM). Three types of pores including residual interparticle pores, grain dissolution pores and micro fractures were identified. A multi-threshold segmentation algorithm was applied to segment the image stacks into three constituents, namely, pore, matrix, and clay. The calculated volumetric fraction of the pore constituent from the segmented image stacks was smaller than experimental porosity, because a certain amount of porosity was also contributed by clay constituent. The PSD of the samples was found to be unimodal in the range of 3–69 μm, with the peak at around 10–15 μm. The clay constituent led to the increase in the overall connectivity of the images stacks, indicating that clays bridged the isolated pores. By assigning appropriate porosity and permeability to the clay constituent, calculated permeability of the samples using REV scale LBM well matched the experimental data. This study provides new insight into characterization of pore structure of tight oil sandstones by μXCT technique.

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.

Non-Darcy flows associated with high Reynolds numbers often occur in the near-wellbore regions of gas reservoirs or hydraulic fractures and thus should not be ignored. However, investigating non-Darcy flow in these porous rocks through laboratory experiments is always expensive and time-consuming. As such, this article sought an alternative method, and a lattice Boltzmann study of non-Darcy flow in various porous models was performed. The applicability of two non-Darcy correlations in porous media and the effect of pore structure on non-Darcy flow were examined. In addition, the reasons for the deviation from the linear Darcy flow and different flow patterns related to inertial effects of the fluid were also studied. The results showed that the characterization of non-Darcy flow in porous media with the cubic law can only be valid in a narrow range of Reynolds number beyond the Darcy regime, outside of which the strong inertia-dominated flow yields to the quadratic correction. On the whole, representing the non-Darcy flows using the quadratic correction is acceptable, especially for porous media with a higher complexity. The features of non-Darcy flow greatly depend on the pore structure of a porous medium, and more heterogeneous pore models always have a faster cessation for Darcy flow and a higher β factor. Furthermore, for simple porous media a small amount of parameters may be adequate for the prediction of the β factor; while the correlations involving more parameters would be needed to determine the β factor for more intricate porous models, although such correlations may not be widely used in various industries. Besides, the non-Darcy flow that occurs in porous media is collectively controlled by different mechanisms. At elevated velocities, the inertial core effect in a large channel will lead the flow to be more homogeneous and less tortuous, while in porous models with complicated pore space, the steady eddy and reversal flow resulting from drag force will make the flow paths more tortuous. As such, it is the hope of this study to provide some new insights into the non-Darcy flow in porous media.

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.

Wettability determines the spreading or adherence behavior of fluids at the solid surface and significantly influences the displacement and entrapment of multiphase fluids in porous media. The present study sets out to determine how wettability controls the imbibition physics of oil and water in a matrix–fracture medium. The displacement and distribution characteristics of fluids, the types of flow regimes, and the fluid morphology under various conditions were revealed in depth. The influences of wettability on oil recovery and energy conversion were analyzed. Finally, the application of the conventional scaling model to simulated imbibition data was also discussed. Results show that the imbibition front is complete and stable in a water-wet medium with the one-end open boundary condition. There are three flow regimes occurring in countercurrent imbibition, depending on the wettability and Ca (capillary number) situations. Increasing θ (contact angle, the affinity of wetting phase to the solid) or Ca can shift the flow pattern from the capillary regime to the capillary-viscous regime to the viscous regime. Additionally, the imbibition oil recovery is greatly affected by wettability, and a more water-wet state does not signify a larger oil recovery. There is a power-law relationship between the oil recovery and the fractal dimension of the nonwetting phase. On the other hand, we performed the energy conversion analysis in the strongly water-wet condition. The external work is positive for both the capillary-viscous and viscous regimes and declines with the decreased Ca. Oil recovery could be linked to the surface energy ratio to some degree, which is relevant to Ca. For the capillary regime, oil recovery is proportional to the final reduced surface energy and does not have an evident relationship with the dissipation energy ratio. Through scaling the recovery factor data vs time via the linear, the power-law, and the conventional models, we find that the conventional scaling model can be used to fit the data point, and the fitting performance is good when Ca is relatively high. However, the linear model is more appropriate when scaling the data in low Ca. Overall, our pore-scale simulation study could pave the way for a further step toward investigating other influencing factors on imbibition behaviors of fluids in more complex media like natural rock materials, which exhibit strong heterogeneity of wettability and pore structure.

Cubic equation of state (EOS) is vital to density calculation in shale gas experimental and theoretical adsorption studies. However, plenty of cubic EOSs have been given and their accuracies on density calculation were still uncertain. Therefore, it is necessary to analyze the applications of different types of cubic EOSs on shale gas adsorption study, according to the density calculation accuracy. Seven Peng-Robinson (PR) type EOSs and eight Soave-Redlich-Kwong (SRK) type EOSs were selected due to their application effect on shale gas. With grand canonical Monte Carlo (GCMC) density data and widely recognized Setzmann-Wagner (SW) EOS, these 15 cubic EOSs were compared and analyzed. Furthermore, cubic and SW EOSs were applied to simplified local density (SLD) model, and the effect of calculated density on adsorption simulation was investigated with GCMC adsorption data. Generally, the densities from PR type EOSs are larger than GCMC data. The SRK type EOS modified by Ghanbari and Check (SRKGC) is as accurate as SW EOS with a small error, 0.6%. The SRK type EOS modified by Morch et al. has the largest error, which is 7.99%, and is inappropriate to shale gas study. The effect of density accuracy on adsorption simulation could not be neglected. With larger bulk density, absolute adsorption value would get larger, while excess adsorption value would be smaller. This research could be a reference to experiment, molecular simulation, density functional theory and SLD methods for shale gas adsorption study, and the calculation accuracy could be improved effectively.

Atomic force microscopy (AFM), which allows 3D construction, nondestructive, and has a high resolution has been used to describe the pore structure of unconventional reservoirs. Due to its scalability, convenience, and flexibility, scanning electron microscopy (SEM) is widely conducted to describe the surface morphology of unconventional reservoirs. However, the two technologies are rarely combined to achieve fast and effective observations of the pore structure of unconventional reservoirs at the same location of the same sample (SLSS). In this study, nanoindentation technology is introduced to create a marked district (MD). Afterward, fast and effective observations of the pore structure of tight sandstones at the SLSS can be realized by searching this identifiable district with AFM and cold-field scanning electron microscopy (CF-SEM). The results demonstrate that AFM and CF-SEM rapidly capture observations of the surface morphology of tight sandstones at the SLSS. The method used in this study accomplishes the goal of fast and effective scanning at the SLSS (only a few minutes), while exhibiting the high potential of combining AFM and CF-SEM for comprehensively investigating the pore structure of reservoirs ranging from nanoscale to microscale. The most unique component of the presented method is that it is especially for the in situ observation of variations in the surface properties (morphology, electric, mechanical, surface force, and roughness) and pore size of all heterogeneous materials subjected to various external stimuli because the applied experimental technologies (nanoindentation, AFM, and CF-SEM) are all exhibit nondestructive properties.

Understanding gas transport in shale matrix is of great significance for reservoir evaluation and gas well productivity. Up to now, numerous transport models were developed based on the hypothesis of homogeneous confined cylindrical nanopores by coupling with multiple mechanisms. In this work, a new transport model is proposed by coupling different transport mechanisms employing the volume fraction of organic matter (OM) instead of the total organic carbon content (TOC). The signature that the OM density is generally lower than the bulk matrix is also considered. The porosity of OM and inorganic matter (iOM) is determined by rock pyrolysis analysis, respectively. Water distribution in OM and iOM pores in the form of water clusters and adsorbed water films is quantified by water adsorption experiments. Gas transport model in moisturized shale matrix pores is then established considering the difference in water distribution. Meanwhile, both of the proposed models are analytical solutions with the hypothesis that the OM and iOM are arranged parallelly. The impacts of different factors on gas transport capacity are analyzed and discussed. Results indicate that the apparent permeability of the shale matrix decreases with the decline of pore radius. For the same pore diameter, the gas transport capacity of OM pores is much greater than that of iOM pores. The apparent permeability decreases with the increasing OM fraction. The irreducible water within the shale matrix can reduce the gas flow capacity considerably, and the apparent permeability is more sensitive to the change of irreducible water saturation at low pressure comparing with that at high pressure. This study sheds fundamental light on the gas transport distinctions in dry and moisturized shale matrix, which provides insights into the development of water-bearing shale gas reservoirs.