Spontaneous Imbibition Of Water Research Articles

Imaging porosity evolution of tight sandstone during spontaneous water imbibition by X-ray Micro-CT

Water imbibition is an important process in reservoir rocks during hydraulic fracturing and water-based enhanced oil recovery operations. However, the water imbibition behavior in tight sandstones has not been fully understood due to their complex pore structure, including the presence of nano and micron-sized pores and throats, surface properties, and wide variation in mineralogy. The present study focuses on the effect of spontaneous water imbibition on the porosity evolution of a tight sandstone. Within this context, a core of Torrey Buff sandstone was characterized by using a combination of multiscale imaging methods (X-ray Computed Tomography, Scanning Electron Microscopy), laboratory experiments (porosity-permeability measurements), and analytical techniques (X-ray Diffraction, Fourier Transform Infrared Spectroscopy, Scanning Electron Microscopy-Energy Dispersive Spectroscopy, and Thermogravimetry). The studied tight sandstone core has a porosity of 12.3 % and permeability of 2.05mD with minerals of quartz (58 %), clays (kaolinite and illite, 23 %), K-feldspar (7 %), dolomite (7 %) and calcite (5 %). Primary and secondary pores, ranging in size from 60 to 140 μm and 30–50 μm, respectively, are mostly filled with highly-soluble carbonate minerals and hydrophilic illite, which influence the spontaneous water imbibition capacity of the tight sandstone. The multiscale imaging technique indicates that after a 10-h long water imbibition experiment, the average pore size of the tight sandstone increased by 1.28 %, reaching 2.35 % at the rock-water contact and 0.13 % at the top of the core. In other words, throughout the core, the porosity changes upon water imbibition are not uniform but show an almost linear trend. This observation could be explained by the significant contribution of highly-soluble carbonates and hydrophilic illite on the microstructure of the tight sandstone. This study implies that multiscale imaging techniques, crucial in examining spontaneous water imbibition, hold promise for further research in enhanced oil recovery or hydraulic fracking in tight sandstones.

Minimum resistance radius for gas–liquid spontaneous imbibition in microtubes

Spontaneous imbibition is the natural movement of a wetting phase liquid within porous media or microtubes. Such flow occurs commonly in nature and industrial settings, where gas and liquid phases flow spontaneously through porous materials. To delve deeper into the characteristics and mechanisms of gas–liquid two-phase spontaneous imbibition at the microscale, this paper establishes a mathematical model considering acceleration. Through both numerical simulations and experiments, the detailed analysis of de-ionized water's spontaneous imbibition within microtubes sheds light on interface phenomena at the microscale. The results highlight the pronounced influence of the microtube radius and gas-water interfacial tension on the imbibition process. By combining experimental work, theoretical analysis, and numerical simulations, this study identifies the minimum resistance radius—a tube radius leading to the shortest imbibition time to the top. The research underscores the significance of considering acceleration and provides a theoretical groundwork for leveraging spontaneous imbibition. It also holds potential value for applications in microfluidic technology, nanomaterial synthesis, and biomedical fields.

Quantitative Study of the Effects of Pore Structure and Wettability on the Water Spontaneous Imbibition Behaviors in Coal

Quantitative Study of the Effects of Pore Structure and Wettability on the Water Spontaneous Imbibition Behaviors in Coal

Shale Matrix Petrophysical Evolution due to Spontaneous Water Imbibition.

Shale matrix alteration resulting from fracturing water-rock interactions has become a major concern. It significantly affects economic production from shale gas formation. Previous studies mostly failed to investigate the thickness of the water intrusion zone and quantified its effects on shale geophysical alteration. As a result, we present a one-dimensional countercurrent water imbibition model in which capillary pressure and chemical osmosis stress are included. This model is used to predict water front movement with respect to soaking durations. Based on the simulation results and theory derivations, the matrix porosity-permeability and mechanical alteration models are set up to reveal shale geophysical variables change due to shale-water interactions. Our results show that during the water imbibition process, capillary pressure plays a more crucial role than osmosis pressure. Furthermore, both core-scaled porosity and permeability are negatively associated with water saturation, the extent of which depends on different driving forces and penetration depth. Finally, water soaking is quantitatively demonstrated to induce an increase in compressive strength and stress sensitivity but a reduction in the elastic modulus. These findings will provide efficient insights into driving mechanisms involved in the water-rock interactions. The study is useful to be incorporated into production models for predicting hydrocarbon production from shale reservoirs.

Pore-scale experimental investigation on the co-current spontaneous imbibition of gas–water two-phase with gravity force

Gravity and capillary forces play pivotal roles in the natural capillary-driven spontaneous imbibition process. The opacity of the medium and the intricate pore structure make it challenging to elucidate the influence of gravity force on co-current gas–water imbibition. A series of pore-scale visualization experiments were conducted using capillary tubes of five different diameters (100, 300, 400, 500, and 1000 μm). The vector concept, represented by the interaction angle with the horizontal direction, was employed to quantify the varying levels of gravity force in the imbibition process, and its impact on imbibition recovery was assessed quantitatively. The findings revealed that the primary influence of gravity on gas–water spontaneous imbibition recovery was predominantly observed in the early stage. Due to the water blocking effect, the gas–water spontaneous imbibition process temporarily halted and resumed when the capillary diameter was 300 μm (at an angle of 60°). For capillary diameters between 100 and 500 μm, the water blocking effect induced a wave-like variation in gas–water spontaneous imbibition recovery as the interaction angle increased. Conversely, for a capillary diameter of 1000 μm, imbibition recovery exponentially decreased with the interaction angle, and no water blocking effect was observed. Consequently, the critical range of pore sizes for the water blocking effect in the gas–water spontaneous imbibition process was determined to be between 500 and 1000 μm. This research offers valuable theoretical insights into understanding capillary-driven flow phenomena in porous media.

Effects of Fracturing Fluids Imbibition on CBM Recovery: In Terms of Methane Desorption and Diffusion

Summary Hydraulic fracturing technology has been widely used to improve the productivity of the coalbed methane (CBM) reservoir, during which tons of fracturing fluids infiltrate the coal seam. However, the effects of fracturing fluids imbibition on CBM recovery are still unclear. In this study, spontaneous and forced water imbibition experiments in methane-bearing low-volatile bituminous (LVB) coal were conducted at various gas adsorption equilibrium pressures, following which methane desorption and diffusion experiments were performed. These experiments simulated the complete process of fracturing fluid imbibition during well shut-in and subsequent methane production upon reopening, which is helpful in understanding the impact of fracturing fluid imbibition on CBM production. The results show that water imbibition displaces adsorbed methane in the coal matrix, and with reservoir pressure increasing, the displaced effect decreases. Furthermore, the forced imbibition (FI) displaces less methane than the spontaneous imbibition (SI) due to water rapidly filling fractures and blocking methane migration out of the matrix in the FI. In the initial stages of gas production following spontaneous or forced water imbibition, the displaced methane diffuses out of the coal at a rapid rate and then slows down. Furthermore, in the case of FI, a significant amount of residual gas remains after desorption and diffusion due to the water blocking effect. However, the water blocking effect has a minimal impact on coal undergoing SI. In terms of desorption and diffusion, this study provides a comprehensive understanding of the effects of fracturing fluids imbibition on recovery of CBM, which is useful for practical shut-in operations following hydraulic fracturing in LVB coal seams.

Modeling moisture infusion in ceramic using Richards equation: Experimental and analytical validations, and exploration of three time-dependent wetting scenarios

Spontaneous imbibition of water into ceramic tile is modeled using the well-known Richards equation (RE) employed for modeling unsaturated flow in the vadose zone. The Brooks and Corey model for relative permeability and Van Genuchten model for capillary pressure is employed to generate the final form of RE that predicts moisture migration in porous ceramic. COMSOL is employed to numerically solve RE in a cuboid, block like ceramic geometry. The simulation results, obtained using the mesh optimized through a grid independence test, are validated in three different ways. First, the simulation predictions are compared with the experimental results obtained from a neutron microscope imaging study of wetting of a ceramic block. Good qualitative and quantitative matches were obtained. Later, the simulation predictions for a 1-D moisture migration situation were compared with two different published analytical solutions, and once again, good agreements were observed. After the code validation, simulations for moisture migration through evolving saturation plots were carried for three different cases of the ceramic-block top getting wetted by falling drops: a single droplet, two droplets with a time gap, and continuous droplets. Evolution of saturation plots were studied where the third case was observed to cause the maximum water infiltration into ceramic.

Experimental Study on Spontaneous Imbibition of Coal Samples of Different Ranks Based on the NMR Relaxation Spectrum.

The comprehension of the mechanisms governing spontaneous water imbibition in gas-water systems plays a significant role in the operation of hydraulic fracturing and the development of coalbed methane (CBM). In this study, nuclear magnetic resonance (NMR) techniques were used to investigate the pore structure and fluid behavior of different rank coal samples during spontaneous imbibition. Analyses were conducted on the 1D NMR T2 spectrum, 2D NMR T1-T2 spectrum, and layer division T2 spectra to achieve accurate and detailed information about the internal pore structure of coal and the characteristics of fluid transport during spontaneous imbibition. Low-rank coal exhibits good pore connectivity and favorable pore sorting characteristics, indicating favorable reservoir conditions. High-rank coal has larger pore spaces and highly developed micropores, which are highly beneficial for gas adsorption. However, its poor pore sorting characteristics and connectivity limit the migration and diffusion of fluids within the reservoir. The imbibition capacity follows a specific order of contribution, with small pores (10-50 nm) having the most significant role, followed by micropores (2-10 nm), ultramicropores (r < 2 nm), mesopores (50-1000 nm), macropores (1000-10,000 nm), and microfractures (r ≥ 10,000 nm). Low-rank coal stands out due to the restricted development of ultramicropores and small pores, leading to a different contribution of imbibition capacity compared to other samples, where macropores and microfractures dominate over all pore types. The coal reservoirs with favorable pore sorting characteristics and pore connectivity tend to exhibit a tendency toward rapid saturation and attainment of a prompt stable state during the hydraulic fracturing process. Finally, the mechanism of the late retreat effect of imbibition and the laws governing different coal ranks, pore structures, and fluid transport were discussed. This study offers comprehensive analyses of the mechanism of coal spontaneous imbibition and the characteristic laws of fluid seepage, providing insights into the optimization of CBM recovery and reservoir management.

Characterization of water migration behavior during spontaneous imbibition in coal: From the perspective of fractal theory and NMR

The spontaneous imbibition (SI) of water plays a crucial role in determining the wetting effect of water injection in coal seams. It is significant to investigate the flow behavior of water in coal during the SI. Contact angle measurement, SI experiment, and low-field nuclear magnetic resonance (LF-NMR) tests have been conducted to measure the properties of coal from different regions of China. The mass change of the coal by SI is related to the square root of time divided into three-stage linear functions in which the slope represents the imbibition rate of coal. The imbibition rate decreases with the increased SI time. The contact angle of bituminous coal is smaller than that of anthracite and is negatively proportional to the SI rate and capacity index C. Water is primarily stored in the adsorption and seepage pores, and little in microfractures. It shows that the fractal dimensions of the partial free pore (Db) and total pores (D) decline in a form of power law, while the fractal dimension of the free pore (Dz) declines irregularly. D-10 and D10 are strongly linear with the T2 spectrum area of adsorption pores, seepage pores, and microfractures, respectively. It indicates that the low-probability measurement area can represent the adsorption pores, and high-the probability measurement area represents seepage pores and microfractures. Adsorption pores play an important role during SI (DSI). The difference between the amplitude increments of adsorption pore and that of seepage pores/microfractures is the key factor affecting multifractal parameters of T2 spectra. The linear relationship between H and Db reveals that water preferentially enters a pore with lower roughness and better connectivity DSI. The process of SI has been divided into three stages in terms of SI rate. The transport process of water within the coal at different stages has been discussed as well. The results of this work are of great significance for optimizing the coal seam water injection and reducing the risk of underground coal mine disasters.

Competitive adsorption effect during spontaneous external water imbibition in loaded gas-bearing coal and application of a normalized desorption rate model

The competitive adsorption effect of water and gas during the coal seam water injection process plays an important role in improving the coalbed methane (CBM) drainage rate of coal seams that do not meet the standards for gas drainage. However, competitive adsorption mainly occurs in the spontaneous imbibition process for coal seam water injection, which is not clear under the dual action of ground stress and gas pressure during spontaneous imbibition process. Here, some spontaneous imbibition experiments under isobaric water addition and isobaric desorption conditions are conducted using a spontaneous imbibition experimental system. The obtained results are as follows. (1) The accumulated replacement gas degree is negatively correlated with the gas pressure, which shows that the principle of spontaneous imbibition can be adopted to improve the gas drainage rate for coal seams whose gas drainage is not up to standard. (2) For spontaneous imbibition with loading stress does not change the adsorption pore structure, the average seepage pore diameter is negatively correlated with the wetting range, while the wetting range is positively correlated with the competitive adsorption effect. (3) The spontaneous imbibition process is a process of effectively wetting the pores of gas-bearing coal, which can effectively increase the pore water content and wetting uniformity. (4) A normalized desorption rate model of the relative replacement degree during spontaneous imbibition is established based on the dimensionless method. This study provides a technical method for improving the gas drainage rate for the drainage of substandard low-permeability coal seams.

Analytical solution and parameter estimation for heat of wetting and vapor adsorption during spontaneous imbibition in tuff

An analytical expression is derived for the thermal response observed during spontaneous imbibition of water into a dry core of zeolitic tuff. Sample tortuosity, thermal conductivity, and thermal source strength are estimated from fitting an analytical solution to temperature observations during a single laboratory test. The closed-form analytical solution is derived using Green's functions for heat conduction in the limit of “slow” water movement; that is, when advection of thermal energy with the wetting front is negligible. The solution has four free fitting parameters and is efficient for parameter estimation. Laboratory imbibition data used to constrain the model include a time series of the mass of water imbibed, visual location of the wetting front through time, and temperature time series at six locations. The thermal front reached the end of the core hours before the visible wetting front. Thus, the predominant form of heating during imbibition in this zeolitic tuff is due to vapor adsorption in dry zeolitic rock ahead of the wetting front. The separation of the wetting front and thermal front in this zeolitic tuff is significant, compared to wetting front behavior of most materials reported in the literature. This work is the first interpretation of a thermal imbibition response to estimate transport (tortuosity) and thermal properties (including thermal conductivity) from a single laboratory test.

Insight into spontaneous water-based working fluid imbibition on the dynamic tensile behavior of anisotropic shale

Shale gas is becoming a new energy development focus worldwide with advances in horizontal wells and hydraulic fracturing, and spontaneous water-based working fluid imbibition is one of the strongest phenomena that can impact borehole stability and the gas extraction rate. Our present experimental work was carried out on shale Brazilian discs with 5 different bedding orientations (0°, 30°, 45°, 60° and 90°) after air-drying and spontaneous water imbibition using a split Hopkinson pressure bar. The results illustrate that under the same loading rate (100–900 GPa/s), spontaneous water imbibition obviously weakens the dynamic tensile strength of shale discs, except for shale discs with a bedding orientation of 90° when the loading rate exceeds 400 GPa/s, and does not change the anisotropic dynamic tensile strength variation trend versus bedding orientations. Models that can well fit test data and reveal the coupling effects of bedding orientation and loading rate on the dynamic tensile strength of shale after air-drying and spontaneous water imbibition are proposed. The rate-dependent failure mode only appears among shale discs with bedding orientations of 30°, 45° and 60°, and this phenomenon is exacerbated and more complex after spontaneous water imbibition. Bedding planes of shale discs after air-drying and spontaneous water imbibition both play three different roles in affecting the failure crack propagation, i.e., intersecting propagation, promoting propagation and promoting turning. Finally, the dynamic tensile strength responses of shale after spontaneous water imbibition are analyzed and discussed, and potential field applications in borehole stability, perforation design and hydraulic fracturing are suggested.

Water imbibition and water sealing in water-driven gas reservoirs development

To improve the poor understanding of the mechanism of spontaneous water imbibition in water invasion in gas reservoirs and overcome the difficulty in quantifying imbibed water and its impact on reservoir development, a study is carried out based on development simulation experiments and theoretical analysis of fluid mechanics. Spontaneous water imbibition is an important mechanical mechanism for the formation of a water seal zone in a low-permeability matrix through water invasion in gas reservoirs. Water imbibition experiments into the reservoir were carried out to clarify the trends of the imbibed distance and imbibed fluid volume to establish the theoretical model of imbibition and to make experimental corrections. An application study was performed based on the understanding of water imbibition and water sealing mechanisms and the building of an imbibition model. The water seal zones formed by imbibition during exploitation are predicted, and the seal-breaking pressure and influx of imbibed water in the water seal zone are evaluated. The research findings fully revealed the large impact of water imbibition on the development of water-driven gas reservoirs, providing technical support for the assessment of water sealing and the establishment of water control measures in water-driven gas reservoirs.

Oil Recovery by Low-Rate Waterflooding in Low-Permeability Water-Wet Sandstone Cores

Summary Smart water or low-salinity (LS) water injection are environmentally friendly methods for efficient hydrocarbon recovery. Wettability alteration toward more water-wet conditions and increased spontaneous imbibition (SI) of water are responsible for enhanced oil production. Wettability alteration and SI to expel oil from the low-permeability matrix are time-dependent processes and both injection rate and oil viscosity are important factors affecting the contribution of capillary and viscous forces to oil production. Low flooding rate must be applied in laboratory corefloods to allow for SI and improved sweep to take place. Residual oil saturation by waterflooding and SI has previously been determined in low-permeability limestone and in higher permeability sands under various flooding rates, wetting conditions, and initial oil saturations. In this study, the effect of flooding rate on oil displacement from low-permeability, water-wet Bandera Brown outcrop sandstone cores has been examined. Viscous forces have been varied by injection at two different rates in addition to SI experiments and using mineral oils with different oil viscosities. The results showed small differences in oil recovery by SI and viscous flooding at high and low rates, indicating that capillary forces contribute significantly to the oil mobilization and production process from this low-permeability, water-wet rock. By varying the oil viscosity, the results indicated that capillary forces were especially important for oil displacement at higher oil viscosity as the ultimate oil recovered by low-rate injection was higher than that from the high-rate injection. Capillary number calculations indicated that viscous forces should be dominant in the recovery tests; however, the experiments showed that capillary forces were important for efficient oil displacement from the low-permeability, water-wet cores used in this study. There was no direct link observed between generated pressure drops at high and low injection rates, including SI, and the ultimate oil recovery. Thus, to simulate oil production in the middle of the reservoir, it was concluded that low-rate waterflooding is needed in laboratory tests to allow SI into the matrix to displace oil by positive capillary forces. The combination of using oils that differ in viscosity at different injection rates could add some additional information to the literature on how to increase the efficiency of waterflooding with a low injection rate.

Characteristic Forced and Spontaneous Imbibition Behavior in Strongly Water-Wet Sandstones Based on Experiments and Simulation

Forced and spontaneous imbibition of water is performed to displace oil from strongly water-wet Gray Berea (~130 mD) and Bentheimer (~1900 mD) sandstone core plugs. Two nonpolar oils (n-heptane and Marcol-82) were used as a non-wetting phase, with viscosities between 0.4 and 32 cP and brine (1 M NaCl) for the wetting phase with viscosity 1.1 cP. Recovery was measured for both imbibition modes, and pressure drop was measured during forced imbibition. Five forced imbibition tests were performed using low or high injection rates, using low or high oil viscosity. Seventeen spontaneous imbibition experiments were performed at four different oil viscosities. By varying the oil viscosity, the injection rate and imbibition modes, capillary and advective forces were allowed to dominate, giving trends that could be captured with modeling. Full numerical simulations matched the experimental observations consistently. The findings of this study provide better understanding of pressure and recovery behavior in strongly water-wet systems. A strong positive capillary pressure and a favorable mobility ratio resulting from low water relative permeability were main features explaining the observations. Complete oil recovery was achieved at water breakthrough during forced imbibition for low and high oil viscosity and the recovery curves were identical when plotted against the injected volume. Analytical solutions for forced imbibition indicate that the pressure drop changes linearly with time when capillary pressure is negligible. Positive capillary forces assist water imbibition, reducing the pressure drop needed to inject water, but yielding a jump in pressure drop when the front reaches the outlet. At a high injection rate, capillary forces are repressed and the linear trend between the end points was clearer than at a low rate for the experimental data. Increasing the oil viscosity by a factor of 80 only increased the spontaneous imbibition time scale by five, consistent with low water mobility constraining the imbibition rate. The time scale was predicted to be more sensitive to changes in water viscosity. At a higher oil-to-water mobility ratio, a higher part of the total recovery follows the square root of time. Our findings indicate that piston-like displacement of oil by water is a reasonable approximation for forced and spontaneous imbibition, unless the oil has a much higher viscosity than the water.

Nuclear Magnetic Resonance Experiment on the Influence of Confining Pressure on Spontaneous Imbibition of Water in Coal

Nuclear Magnetic Resonance Experiment on the Influence of Confining Pressure on Spontaneous Imbibition of Water in Coal

Microfluidics experimental investigation of the mechanisms of enhanced oil recovery by low salinity water flooding in fractured porous media

Spontaneous imbibition of water from fracture into the matrix is considered as one of the most important recovery mechanisms in the fractured porous media. However, water cannot spontaneously imbibe into the oil-wet rocks and as a result oil won’t be produced, unless the capillary pressure barrier between fracture conduits and matrix is overcome. Wettability alteration is known as the main affecting mechanism for low salinity water flooding (LSWF), however, its effectiveness in fractured porous media has been less investigated, especially in the case of possible pore scale displacement mechanisms. In this study, the effectiveness of LSWF (diluted seawater) on oil recovery is compared to the formation water (FW) and seawater (SW) in four different fractured models. Each of these fractured models is representing a different sub scale of the NFR. In addition to the effect of fracture geometry, the effect of wetting conditions was studied. Contact angles, Interfacial Tension (IFT) and zeta potentials are measured to have more insight on the Crude-oil/Brine/Rock system under investigation.The results of micromodel experiments show a positive effect of LSWF in both water-wet and oil-wet states. Sessile drop and pendant drop tests show that contact angle alteration and IFT reduction cannot be the dominant mechanisms. Visual investigations on dynamic displacement tests, suggest that the formation of micro-emulsions and elastic oil/water interface are the main mechanisms of recovery in the case of LS and FW injections, respectively. Elastic FW/oil interface causes discontinuous water phase in the fracture, which in turn reduces the mobility of the FW in the fracture and facilitates the diversion of the flow from fracture towards the matrix. This mechanism results in better sweep efficiency for the case of FW compared to the case of SW. Nevertheless, the dominant formation of microemulsion in the case of LSW is more effective in the diversion of the flow from fracture into the matrix (compared to the effect of interface elasticity in the case of FW). This mechanism along with slightly better imbibition (less oil-wet state) in the case of LSWF enhances its recovery performance compared to the FW in both water-wet and oil-wet systems.

Microstructure Evolution of Tight Sandstone During Spontaneous Water Imbibition

Microstructure Evolution of Tight Sandstone During Spontaneous Water Imbibition

Liquid phase blockage in micro-nano capillary pores of tight condensate reservoirs

The development of tight condensate gas reservoirs faces complex formation damage mechanisms, seepage characteristics and hydrocarbon phase changes, which are common challenges for both tight gas reservoirs and condensate gas reservoirs. In the near-well area, the liquid phase blockage problem due to water phase retention formed by capillary spontaneous imbibition of invasive water and oil phase accumulation due to retrograde condensation precipitation has become a key obstacle to the efficient development of tight condensate gas reservoirs. Experiments were conducted to evaluate the damage of liquid phase blockage under different conditions near the wellbore area. The results show that when the liquid phase saturation in the near-wellbore area increased to 80.12%, the relative permeability of the gas phase decreased to 0. It is concluded that the mixed wettability of formation rocks, ultra-low water saturation, abundant hydrophilic clay minerals and high capillary resistance of micro-nano pores are the main causes for the easy adsorption and retention of liquid phase. Reduced pressure transmission capacity and irreversible formation damage induced by liquid-phase blockage are the two major controlling factors for the low liquid phase flowback rate. It is suggested that developing a flowback system based on the formation physical properties differentiation to control water phase invasion, and changing wettability or injecting thermochemical fluid to control condensate blocking are feasible methods to relieve liquid phase blockage damage in tight condensate reservoirs. Cited as: Wang, Y., Kang, Y., Wang, D., You, L., Chen, M., Yan, X. Liquid phase blockage in micro-nano capillary pores of tight condensate reservoirs. Capillarity, 2022, 5(1): 12-22. https://doi.org/10.46690/capi.2022.01.02

Simulation of Counter-Current Spontaneous Imbibition Based on Momentum Equations with Viscous Coupling, Brinkman Terms and Compressible Fluids

A numerical model is investigated representing counter-current spontaneous imbibition of water to displace oil or gas from a core plug. The model is based on mass and momentum conservation equations in the framework of the theory of mixtures. We extend a previous imbibition model that included fluid–rock friction and fluid–fluid drag interaction (viscous coupling) by including fluid compressibility and Brinkman viscous terms. Gas compressibility accelerated recovery due to gas expansion from high initial non-wetting pressure to ambient pressure at typical lab conditions. Gas compressibility gave a recovery profile with two characteristic linear sections against square root of time which could match tight rock literature experiments. Brinkman terms decelerated recovery and delayed onset of imbibition. Experiments where this was prominent were successfully matched. Both compressibility and Brinkman terms caused recovery deviation from classical linearity with the square root of time. Scaling yielded dimensionless numbers when Brinkman term effects were significant.Article HighlightsSpontaneous imbibition with viscous coupling, compressibility and Brinkman terms.Viscous coupling reduces spontaneous imbibition rate by fluid–fluid friction.Brinkman terms delay early recovery and explain seen delayed onset of imbibition.Gas compressibility accelerates recovery and can be significant at lab conditions.Gas compressibility gives recovery with two root of time lines as seen for shale.