Trapped Gas Saturation Research Articles

Enhancing Hydrogen Recovery from Saline Aquifers: Quantifying Wettability and Hysteresis Influence and Minimizing Losses with a Cushion Gas

This study aims to numerically assess the impact of wettability and relative permeability hysteresis on hydrogen losses during underground hydrogen storage (UHS) and explore strategies to minimize them by using an appropriate cushion gas. The research utilizes the Carlson model to calculate the saturation of trapped gas and the Killough model to account for water hysteresis. By incorporating the Land coefficient based on laboratory-measured data for a hydrogen/brine system, our findings demonstrate a significant influence of gas hysteresis on the hydrogen recovery factor when H2 is used as a cushion gas. The base model, which neglects the hysteresis effect, indicates a recovery factor of 78% by the fourth cycle, which can be improved. In contrast, the modified model, which considers hysteresis and results in a trapped gas saturation of approximately 17%, shows a hydrogen recovery factor of 45% by the fourth cycle. Additionally, gas hysteresis has a notable impact on water production, with an observed 12.5% increase in volume in the model that incorporates gas hysteresis. Furthermore, optimization of the recovery process was conducted by evaluating different cushion gases such as CO2, N2, and CH4, with the latter proving to be the optimal choice. These findings enhance the accuracy of estimating the H2 recovery factor, which is crucial for assessing the feasibility of storage projects.

Advanced Digital-SCAL Measurements of Gas Trapped in Sandstone

Trapped gas saturation (Sgr) plays an important role in subsurface engineering, such as carbon capture and storage, H2 storage efficiency as well as the production of natural gas. Unfortunately, Sgr is notoriously difficult to measure in the laboratory or field. The conventional method of measurement—low-rate unsteady-state coreflooding—is often impacted by gas dissolution effects, resulting in large uncertainties of the measured Sgr. Moreover, it is not understood why this effect occurs, even for brines carefully pre-equilibrated with gas. To address this question, we used high-resolution X-ray computed tomography (micro-CT) imaging techniques to directly visualize the pore-scale processes during gas trapping. Consistent with previous studies, we find that for pre-equilibrated brine, the remaining gas saturation continually decreased with more (pre-equilibrated) brine injected and even after the brine injection was stopped, resulting in very low Sgr values (possibly even zero) at the pore-scale level. Furthermore, we were able to clearly observe the initial trapping of gas by the snap-off effect, followed by a further shrinkage of the gas clusters that had no connected pathway to the outside. Our experimental insights suggest that the effect is related to the effective phase behavior of gas inside the porous medium, which due to the geometric confinement, could be different from the phase behavior of bulk fluids. The underlying mechanism is likely linked to ripening dynamics, which involves a coupling between phase equilibrium and dissolution/partitioning of components, diffusive transport, and capillarity in the geometric confinement of the pore space.

The Impact of Relative Permeability Hysteresis on CO2 Sequestration in Saline Aquifer

This work analyzed the amount of capillary-trapped CO2 for maximum residual gas saturation due to relative permeability hysteresis. Upward migration of CO2 is unwanted because it increases the risk of CO2 migration from storage sites to the surface. One way to mitigate CO2 leakage risk is to reduce the vertical CO2 migration to improved storage capacity and containment security. A compositional simulator (CMG-GEM) was used to simulate the flow of two components (CO2 and H2 O). A fluid model was built with the PR 78 EOS using WINPROP. A base case model without relative permeability hysteresis was simulated and compared with the case with relative permeability hysteresis. The amount of CO2 trapped, and CO2 saturation distribution were analyzed for maximum trapped gas saturation of 0.3, 0.4 and 0.5. Results shows an increase in the amount of CO2 trapped as the maximum residual gas saturation was increased from 0.3 to 0.4 and 0.5 with a value of 16560128mol for the base case study, 49041744mol, 59502924mol and 67286728mol respectively for maximum residual gas saturation due to relative permeability hysteresis of 0.3, 0.4 and 0.5 respectively. Very little accumulation of CO2 occurs when the maximum trapped gas saturation due to relative permeability hysteresis was set at 0.5. Result reveals that after 200 years, almost all the CO2 was trapped in the formation. Therefore, the imbibition cycle at the trailing end of the CO2 plume should be considered as accounting for hysteresis effects has led to a spread-out distrib

Effects of pore size and pore connectivity on trapped gas saturation

Abstract Trapped or residual air (or gas) is known to affect the multiphase hydraulic properties of both soils and rocks. Trapped air is known to impact many vadose zone hydrologic applications such as infiltration and flow in the capillary fringe, but is also a major issue affecting recoverable oil reserves. Although many studies have focused on the relationship between porosity and trapped gas saturation (S gt ) in sandstones, far fewer studies have been carried out for carbonate rocks. This work aims to analyze the influence of porous media properties on trapped gas saturation in carbonate rocks. For this we used thirteen Indiana Limestone and Silurian dolomite rock samples from the USA, and several coquinas from the Morro do Chaves formation in Brazil. Pore size distributions were obtained for all samples using Nuclear Magnetic Resonance (NMR), and Mercury Injection Capillary Pressure (MICP) data from three of the samples to determine their pore throat size distributions. Additionally, 3D microtomography (microCT) images were used to quantify macropore profiles and pore connectivities. Results indicate a lower capacity of gas trapping in carbonate rocks in which micro- and mesopores predominate. Results also indicate that in carbonate rocks, pore size exerts a greater influence on the ability of gas trapping compared to pore connectivity, so that rocks with a predominance of macropores have greater capacity for gas trapping, even when the macropores are well interconnected. These findings show that pore characteristics very much affect the processes governing gas trapping in carbonate rocks, and indirectly the multiphase hydraulic properties and recoverable oil reserves of carbonate rock reservoirs.

Analysis of the Influence of Porosity and Permeability on Trapped Gas Saturation

Analysis of the Influence of Porosity and Permeability on Trapped Gas Saturation

Carbonate oil and gas source rocks wettability alteration due to influence of polymer-colloidal drilling mud

Evaluation of rock wettability is an important task, since this parameter determines the distribution of water and oil in the reservoirs and their relative and phase permeability. The reliability of evaluation the wettability of rock samples depends on the drilling-in conditions during core sampling and core sample preparation methods. The investigation of the surface properties of the core from the Orenburg oil and gas condensate field showed that using of polymer-colloidal drilling mud leads to hydrophilization of the samples' surface. To obtain information on the actual wettability values of rock samples taken from wells drilled with polymer-colloidal drilling mud a method for estimating the relative (predominant) wettability of rocks based on petrophysical and lithological studies data is proposed. The authors suggest that the extraction of oil and gas source rock samples leads to irreversible changes in surface properties that cannot be restored. Keywords: selective wettability; relative wettability; predominant wettability; polymer-colloidal drilling mud; residual gas saturation; trapped gas saturation; pore space structure; extraction.

Laboratory Investigation of Impact of Slickwater Composition on Multiphase Permeability Evolution in Tight Sandstones

Summary Fracturing fluid filtrate that leaks off during injection is imbibed by strong capillary forces present in low-permeability sandstones and may severely reduce the effective gas permeability during cleanup and post-fracture production. This work aims to investigate the role fracturing fluid filtrate from slickwater has on rock-fluid and fluid-fluid interactions and to quantify the resulting multiphase permeability evolution during imbibition and drainage of the filtrate by means of specialized core laboratory techniques. Three suites of experiments were conducted. In the first suite of experiments, a fluid leakoff test was conducted on selected core samples to determine the extent of polymer invasion and leakoff characteristics. In the second suite, multigas relative permeability measurements were conducted on sandstone plugs saturated with fracturing fluid filtrate. A combination of controlled fluid evaporation and pulse decay permeability technique was used to measure liquid and gas effective permeabilities for both drainage and imbibition cycles. These experiments aim to capture dynamic permeability evolution during invasion and cleanup of fracturing fluid (slickwater). The final suite of experiments consists of adsorption flow tests to investigate, identify, and quantify possible mechanisms for adsorption of the polymeric molecules of friction reducers present in the fluid filtrate to the pore walls of the rock sample. Imbibition tests and observations of contact angles were conducted to validate possible wettability changes. Results from multiphase permeability flow tests show an irreversible reduction in endpoint brine permeability and relative permeability with increasing concentration of friction reducer. Our results also show that effective gas permeability during drainage/cleanup of the imbibed slickwater fluid is controlled to a large degree by trapped gas saturation than by changes in interfacial tension. Adsorption flow tests identified adsorption of polymeric molecules of the friction reducer present in the fluid to the pore walls of the rock. The adsorption friction reducer increases the wettability of the rock surface and results in the reduction of liquid relative permeability. The originality of this work is to diagnose formation damage mechanisms from laboratory experiments that adequately capture multiphase permeability evolution specific to a slickwater fluid system, during imbibition and cleanup. This will be useful in optimizing fracturing fluid selection.

Generalised model for simulation of two- and three-phase cycle-dependent hysteresis in sandstones

Many Enhanced Oil Recovery (EOR) processes involve injecting multiple slugs to improve the volumetric sweep efficiency in the reservoir, such as Water-Alternating-Gas (WAG), polymer flood, surfactant flood, and steam injection. Precise estimations of hysteresis phenomenon in relative permeability (kr) and capillary pressure (Pc) plays a crucial role in conducting accurate prognosis of oil production, reliable decision making, and feasibility assessment of EOR plans. Over the years, abundant high-quality experimental data revealed limitations of existing hysteresis models in the literature and highlighted the necessity of introducing a reliable hysteresis model.This paper presents a new hysteresis model for accurate estimation of ultimate oil recovery and pressure drop in coreflood experiments. In contrast to the existing models, all required parameters are directly calculated from experimental data, eliminating the tuning procedure, and reducing the associated uncertainties. This study also includes a detailed discussion of estimating trapped gas saturation and application of Land’s trapping model in cyclic systems, considering their importance in CO2 sequestration and non-aqueous contaminant flow in soil. The presented model also benefits from a new procedure for estimating final saturations during a WAG experiment based on common observations of WAG experiments. A comprehensive set of cyclic two- and three-phase experiments performed on a homogenous sandstone over a wide range of injection scenarios, fluid, and rock properties were successfully used to validate the model. The detailed analysis and comparison of various cyclic experiments herein provide an excellent benchmark for future validation and development of hysteresis models.

Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir

Water-alternating-gas (WAG) injection is recommended as a means of improving gas mobility control. This paper describes a series of coreflood tests conducted to investigate the potential for continuous gas injection and WAG injection in ultra-high water-cut saline reservoirs. The mechanisms of immiscible water-alternating-nitrogen injection on residual oil distribution are analyzed, and pore-scale analysis is conducted. The effect of injection parameters on residual oil distribution and recovery efficiency is also evaluated. Coreflood results show that tertiary oil recovery efficiency is significantly higher using WAG injection than continuous gas injection during the ultra-high water-cut period. Pore-scale visualization illustrates the movement of gas through the waterflooded channels into the pore space previously occupied by water and residual oil, which then becomes trapped. Injected gas breaks the force balance of microscopic residual oil and reduces residual oil saturation. This mobilizes the displaced/collected residual oil into large waterfilled pores and blocks several water channels. WAG flooding can decrease free-gas saturation and increase trapped-gas saturation significantly, resulting in decreased relative permeabilities of gas and water. The experimental results indicate that appropriate WAG design parameters could enhance recovery by 15.62% when the injected pore volume of water and gas in the cycle is 0.3 PV at a gas/water injection ratio of 2:1. The results from this study will allow researchers and reservoir engineers to understand and implement immiscible WAG injection as an enhanced oil recovery method in ultra-high water-cut stage reservoirs. Cited as: Kong, D., Gao, Y., Sarma, H., Li, Y., Guo, H., Zhu, W. Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir. Advances in Geo-Energy Research, 2021, 5(2): 139-152, doi: 10.46690/ager.2021.02.04

Effects of hydrogen gas production, trapping and bubble-facilitated transport during nanoscale zero-valent iron (nZVI) injection in porous media

The injection of nanoscale zero-valent iron (nZVI) can be an effective technique for the treatment of groundwater contaminants, including chlorinated solvents. However, its effectiveness can be limited by natural reductant demand (NRD) reactions, including the reduction of water resulting in the production of hydrogen gas. This study presents results from a series of laboratory experiments to investigate gas production and mobilization following the injection of nZVI solutions, along with sodium borohydride (NaBH4) that is used for nZVI synthesis. Experiments were performed in a thin, two-dimensional flow cell (22 × 34 × 1 cm3) to measure hydrogen gas volumes and local gas saturations, and to investigate the distribution of gas within and above the injection zone. An additional experiment was conducted in a larger flow cell (150 × 150 × 2 cm3) containing dissolved trichloroethene (TCE) to assess changes in aqueous flow pathways and enhanced vertical transport of TCE by mobilized gas. The results showed substantial gas production (60% to 740% of the injected solution volume) resulting in gas mobilization as a network of gas channels above the injection zone, with more gas produced from greater excess NaBH4 used during nZVI synthesis. Trapped gas saturations were sufficient to cause the diversion of aqueous flow around the nZVI injection zone. In addition, gas production and mobilization resulted in the bubble-facilitated transport of TCE, and detectable concentrations of TCE and reaction products (ethane and ethene) above the target treatment zone.

Visualizing pore-scale foam flow in micromodels with different permeabilities

The mechanisms of pore-scale foam transport in porous media help further understanding how foam flows in porous media with different permeabilities. In this work, the pore-scale behaviors of N2 foam flows in porous media with different permeabilities have been investigated using transparent polydimethylsiloxane (PDMS) micromodels with foam qualities in the range of 50 %–90 %. The foam transport in homogeneous and heterogeneous micromodels, and the effects of permeability on foam texture and gas trapping, were evaluated through direct visual observations. Bubble generation based on the pre-existing foam bubbles occurred for trapped and flowing bubbles, which could change the distribution of flowing and trapped gases in the micromodel. Two foam generation mechanisms, namely snap-off and lamella division, were observed in this study. The mean size of bubbles in the low-permeability micromodel was smaller than that in the high-permeability micromodel especially at high foam qualities. The trapped gas saturation in the low-permeability micromodel was larger than that in the high-permeability micromodel. For foam flow in the heterogeneous micromodel, the process of foam diversion from the high-permeability region to the low-permeability region was directly displayed at the pore scale. Regeneration of large trapped bubbles in the low-permeability region under the pressure difference across the micromodel played an important role in this process.

Novel approach for predicting water alternating gas injection recovery factor

Water alternating gas (WAG) injection process is a proven EOR technology that has been successfully deployed in many fields around the globe. The performance of WAG process is measured by its incremental recovery factor over secondary recovery. The application of this technology remains limited due to the complexity of the WAG injection process which requires time-consuming in-depth technical studies. This research was performed for a purpose of developing a predictive model for WAG incremental recovery factor based on integrated approach that involves reservoir simulation and data mining. A thousand reservoir simulation models were developed to evaluate WAG injection performance over waterflooding. Reservoir model parameters assessed in this research study were horizontal and vertical permeabilities, fluids properties, WAG injection scheme, fluids mobility, trapped gas saturation, reservoir pressure, residual oil saturation to gas, and injected gas volume. The outcome of the WAG simulation models was fed to the two selected data mining techniques, regression and group method of data handling (GMDH), to build WAG incremental recovery factor predictive model. Input data to the machine learning technique were split into two sets: 70% for training the model and 30% for model validation. Predictive models that calculate WAG incremental recovery factor as a function of the input parameters were developed. The predictive models correlation coefficient of 0.766 and 0.853 and root mean square error of 3.571 and 2.893 were achieved from regression and GMDH methods, respectively. GMDH technique demonstrated its strength and ability in selecting effective predictors, optimizing network structure, and achieving more accurate predictive model. The achieved WAG incremental recovery factor predictive models are expected to help reservoir engineers perform quick evaluation of WAG performance and assess a WAG project risk prior launching detailed time-consuming and costly technical studies.

Time dependent self-diffusion coefficient of methane molecules confined into micropores structure of a sandstone

In this work, the effect of pore structure of a sandstone on the molecular displacement of confined methane gas is analyzed. It was found that the self-diffusion coefficient of a methane molecule depends on the pore size distribution an their connectivity. In particular, the time dependent self-diffusion coefficient exhibits a maximum which is correlated with the effect of the molecular confinement. It was found that a sandstone with small pores and/or pores bad connected traps the gas more efficiently than other pores structures. This fact enable to understand the scattered values which the residual trapped gas saturation measures exhibit with different sandstones.

Injection of disposal water from a geothermal reservoir into a gas reservoir

In this paper, we assess and model new strategies for integration of geothermal energy with gas production in the Oude Leede Gas Field in the Netherlands. We investigate the injection of cooled geothermal water into a gas field located just few kilometers away from the geothermal reservoir in the Netherlands. This synergy type can be considered for economic natural gas production from a gas field in the proximity of a geothermal doublet project and improved energy production in the geothermal reservoir. A 3-D model including a gas trapping mechanism was built to study the possible production potential of the gas field. Water flooding compensates pressure loss by reducing the pore space, however it complicates the process by introducing trapped gas. We studied the effect of injection rate, permeability, saturation condition before flooding and reservoir pressure on the ultimate gas recovery and the residual trapped gas saturation. Injecting water will increase the ultimate recovery factor for higher abandonment pressure. Higher water injection rates will keep the reservoir pressure up, increase the trapped gas saturation, and hence reduce the maximum recovery. The presence of heterogeneity and capillary forces has minor effects on the gas recovery factor. The exergy recovery factor of a water injection process is higher than a gas compression process due to the large amounts of energy required for compression. Considering net present value (NPV) analysis for a higher abandonment pressure, water injection is economically preferable, however not feasible. At a lower abandonment pressure, natural gas depletion can easily compete with the water injection process due to the higher costs of water injection and drilling.

An improved brine-relative permeability model with hysteresis and its significance to sequestrated CO2 in a deep saline aquifer

Relative permeability is the fundamental petrophysical property that governs the flow and distribution of sequestrated CO2 in a deep saline aquifer, which conceptually has implications on the dissolution and capillary trapping mechanisms. The significance of trapped-gas saturation on the imbibition-relative permeability of wetting brine phase has been less emphasized in the literature. Numerically computing the hysteretic brine-relative permeability at every nodal point corresponding to the wetting phase saturation (saturation history) is a challenge. Whereas, the complexity is associated with computing the endpoint-relative permeability of brine phase corresponding to the wetting phase saturation at which flow reversal is taking place. In the present paper, an improved hysteresis-relative permeability model for wetting brine phase using Land’s trapping coefficient has been presented. The present relative permeability model has been validated using the experimental results from the literature. The sensitivity of considering hysteresis brine-relative permeability on flow and distribution of sequestrated CO2 in a deep saline aquifer has been numerically investigated. The observed results emphasize that the flow model, without considering the brine-relative permeability hysteresis, over-predicts the distribution of sequestrated CO2 in the system of porous medium considered.

A Comparative Study of Gas Flooding and Foam-Assisted Chemical Flooding in Bentheimer Sandstones

A laboratory study of principal immiscible gas flooding schemes is reported. Very well-controlled experiments on continuous gas injection, water-alternating-gas (WAG) and alkaline–surfactant–foam (ASF) flooding were conducted. The merits of WAG and ASF compared to continuous gas injection were examined. The impact of ultra-low oil–water (o/w) interfacial tension (IFT), an essential feature of the ASF scheme along with foaming, on oil mobilisation and displacement of residual oil to waterflood was also assessed. Incremental oil recoveries and related displacement mechanisms by ASF and WAG compared to continuous gas injection were investigated by conducting CT-scanned core-flood experiments using n-hexadecane and Bentheimer sandstone cores. Ultimate oil recoveries for WAG and ASF at under-optimum salinity (o/w IFT of 10−1 mN/m) were found to be similar [60 ± 5% of the oil initially in place (OIIP)]. However, ultimate oil recovery for ASF at (near-)optimum salinity (o/w IFT of 10−2 mN/m) reached 74 ± 8% of the OIIP. Results support the idea that WAG increases oil recovery over continuous gas injection by drastically increasing the trapped gas saturation at the end of the first few WAG cycles. ASF flooding was able to enhance oil recovery over WAG by effectively lowering o/w IFT (< 10−1 mN/m) for oil mobilisation. ASF at (near-)optimum salinity increased clean oil fraction in the production stream over under-optimum salinity ASF.

Relative Permeability Measurements during the Exsolution and Dissolution of Hydrogen Gas Produced by the Hydrolysis of Sodium Borohydride

Core Ideas Aqueous relative permeability experiments followed gas exsolution and trapping. Hydrogen gas was produced by the reaction of sodium borohydride and water. Internal drainage, external drainage and imbibition, and dissolution were compared. Trapped gas saturations were higher following internal drainage. Aqueous relative permeability was similar for internal and external displacement. The presence of trapped gas in otherwise water‐saturated porous media has a substantial effect on water flow, which is important to a wide variety of subsurface applications including groundwater remediation, CO2 sequestration, and the release of greenhouse gases associated with oil and gas development. Trapped gases can be created by external drainage and imbibition, where fluids invade from system boundaries, or by internal drainage (exsolution), where gas is produced at nucleation sites within a porous medium. A series of laboratory experiments were conducted in thin flow cells, in which H2 gas was produced by the reaction of sodium borohydride and water to produce a range of trapped gas saturations. Aqueous relative permeability was measured following H2 exsolution and during dissolution and compared with measurements in the presence of air trapped by external drainage and imbibition. The results showed that gas saturations higher than those produced by external displacement remained trapped (immobile) when produced by exsolution but that aqueous relative permeability was similar at the same gas saturations. The results of this study suggest that traditional aqueous relative permeability relationships based on external drainage may be suitable to describe the effects of internal drainage in uniform, loosely packed sands. However, additional investigation across a wider range of porous media and at higher gas saturations is required.

An Investigation of Recovery Mechanisms for Oil Field Optimization by Three-Phase Core Flood and Simulation Studies

Two potential recovery mechanisms are being considered for a major field which required laboratory measurements to investigate the efficiency of the two scenarios: gas flood followed by water flood and water flood followed by gas flood. Although simply stated, the recovery scenarios involved complex three-phase processes which had to be replicated in the laboratory at reservoir conditions to provide reliable data upon which reservoir development decisions could be made. The first sequence consisted of water displacing oil to residual oil saturation (Sorw), oil displacing water to residual water saturation (Swro) and gas displacing both oil and water to Sor3φ,g and Swr3φ,g. The second sequence consisted of gas displacing oil to residual oil saturation (Sorg), oil displacing gas to trapped gas saturation (Sgto) and water displacing both oil and gas to Sor3φ,w and Sgt3φ,w respectively. Composite cores of four well-matched plugs at Swi were used and all measurements were made at bubble point conditions. A vertical core holder was housed inside a reservoir condition facility equipped with gamma attenuation saturation monitoring (GASM). Temperature stability and the use of GASM were paramount for the accurate measurement of produced fluids, especially trapped gas saturation. Oil, gas and water produced volumes were also measured using a separator housed inside the core flood oven to provide optimum temperature stability. The laboratory results were modelled in a compositional simulator using an equation of state tuned to conventional PVT data and both swelling and multiple contact experiments. The objective was to build a three-phase predictive model from the constituent two-phase relative permeability data. The paper details the experimental methods and presents results for each section of the two sequences. The key conclusions are that Sorg&gt;Sorw&gt; Sor3φ,g&gt; Sor3φ,w and Sgt3φ,w&lt; Sgto.

A CT-scanner study of foam dynamics in porous media

We report an experimental study of N2-foam injection in a Bentheimer sandstone coupled with X-ray Computed Tomography (CT-scanner). The measurements of pressure drop and gas saturation at different flow rates and foam qualities allowed us to describe the foam dynamics under transient and steady-state flow conditions. The brine displacement by foam shows a transient piston-like displacement pattern taking place in two successive phases. Saturation profiles reveal permanent entrance effects related to the injection procedure, and transient downstream end effects related to the gradual foam build-up. Entrance effects are attenuated with a high foam quality and at low total flow rate. The rheological behavior of foam was studied in terms of apparent foam viscosity and foamed-gas mobility as a function of foam quality and gas interstitial velocity. In the low-quality regime, foam exhibits a shear-thinning behavior that can be modelled by a power function. Furthermore, for a fixed total velocity, the quasi-invariance of strong foam apparent viscosity values is shown to result from the slight increase of trapped gas saturation, within the commonly-admitted assumption of invariant foam texture in the low-quality regime. An increase in gas mobility was observed above a certain value of the foam quality. That transition between low-quality and high-quality regimes was related to a limiting capillary pressure of foam in the porous medium under consideration.

Fluid saturation evolution with imbibition in unconventional natural gas reservoirs

Hydraulic fracturing plays an important role in developing unconventional natural gas. The large amount of fracturing fluid retention becomes a significant phenomenon in gas fields. Much research has been carried out to explain this mechanism. Imbibition is regarded as one of the important factors and has been investigated extensively. However, the saturation evolution of different types of fluids (liquid, free gas, and trapped gas) has been less researched during imbibition. A porosity experiment combined with an imbibition experiment was conducted to research the fluids-saturation evolution. There are three types of experimental rocks: tight sand, volcanic rock, and shale. The free-gas saturation decreases with the increasing liquid saturation in all samples. However, the sum of these two types of saturation is approximately 100% during imbibition in tight sand. This indicates that the pore space is almost totally filled by liquid and free gas. The sum of these two types of saturation is less than 100% during imbibition in volcanic rock. This indicates that there is trapped gas by liquid. Trapped-gas saturation increases at the early period and decreases at the late period. The sum of these two types of saturation greatly exceeds 100% during imbibition and increases with the imbibition time in shale rocks. This means that there is large amount of extra imbibition liquid. At the same time, the free-gas saturation fluctuates with the increasing liquid saturation. Based on the above results, it can be concluded that tight sand reservoirs have nearly no trapped gas and extra imbibition liquid, volcanic reservoirs have trapped gas and a little extra imbibition liquid, and shale reservoirs have some trapped gas and a large amount of extra imbibition liquid. This research contributes to understanding the fluid saturation evolution during hydraulic fracturing in unconventional natural gas reservoirs.