Jamin Effect Research Articles

Five-stage dynamics of discontinuous oil phase migration in the constricted microchannel: A quantitative analysis of the Jamin effect

The transport of discontinuous oil phases in constricted microchannels is a significant issue within the domains of the petroleum industry, bioengineering, and other industrial processes. During the transport, there is a pressure obstructing the drop flow through the narrow throat, which is named the Jamin effect. In this study, computational fluid dynamics technique is employed to observe and analyze the pressure drop of the discontinuous oil phase during its passage through a constricted microchannel and provides a quantitative analysis for the Jamin effect. The results show that the discontinuous oil phase undergoes five stages during its migration in the constricted microchannel, namely, the preparatory stage, the development stage of the forward meniscus, the quasi-stable stage, the regression stage of the rear meniscus, and the stable stage. Moreover, the composition of resistance in the Jamin effect is not solely due to capillary pressure, as traditional scholars believe. The analysis indicates that the equivalent viscosity of the discontinuous oil phase remains consistent during both the preparatory stage and the stable stage, demonstrating that the magnitude of the equivalent viscosity is unaffected by the profile of the oil phase. Additionally, the effects of oil phase saturation, viscosity, and capillary number on the Jamin effect also have been discussed.

Nano-SiO2 enhanced slickwater fracturing fluid for improved imbibition recovery in tight gas reservoirs: Performance and mechanism

Inspired by the exceptional performance of nanomaterials in oilfield development, yet it is rarely applied in tight gas reservoir. In this study, focusing on the tight gas reservoir of the Liuyangbao, Ordos Basin, a slickwater fracturing fluid was synthesized by incorporating nano-SiO2 and surfactant to enhance its stability and activity, aiming to optimize the utilization efficiency of slickwater. The prepared SiO2-enhanced slickwater fracturing fluid exhibited excellent interfacial regulation properties involving surface tension reduction (71.65–28.31 mN/m) and wettability alteration (69.3–21.5º). In addition, SEM images indicated that the self-assembled nano-SiO2 adsorbed on the core surface, sequentially forming a large number of micro/nano structures in “spot adsorption”, “sheet adsorption”, “lobe adsorption” and “cluster adsorption” shapes, altering the original pore structure. Meanwhile, LP-N2GA results showed an upward shift in the hysteresis loop of isotherms after nano-SiO2 was adsorbed on the core samples, with a considerable increase in specific surface area (SSA) and transitional pores. Moreover, the system showed an outstanding capacity for imbibition gas production, and finally recovered 78.2 % (∼21.4 % higher than slickwater system). The underlying mechanism responsible for the system enhanced gas recovery were attributed to capillary pressure, structural disjoining pressure and Jamin effect. This work provides feasibility of the application of nano-SiO2 in the development of tight gas reservoirs.

Characteristics of Supercritical CO2 Non-Mixed Phase Replacement in Intraformational Inhomogeneous Low-Permeability Reservoirs

Under the influence of the sedimentation process, the phenomenon of intraformational non-homogeneity is widely observed in low-permeability reservoirs. In the development process of water and gas replacement (WAG), the transport law of water and gas and the distribution of residual oil are seriously affected by the non-homogeneity of reservoir properties. In this paper, a study on two types of reservoirs with certain lengths and thicknesses is carried out, and a reasonable development method is proposed according to the characteristics of each reservoir. Firstly, through indoor physical simulation experiments combined with low-field nuclear magnetic resonance scanning (NMR), this study investigates the influence of injection rate and core length on the double-layer low-permeability inhomogeneous core replacement and pore throat mobilization characteristics. Then, a two-layer inhomogeneous low-permeability microscopic model is designed to investigate the model’s replacement and pore throat mobilization characteristics under the combined influence of rhythmites, gravity, the injection rate, etc. Finally, based on the results of the core replacement and numerical simulation, a more reasonable development method is proposed for each type of reservoir. The results show that for inhomogeneous cores of a certain length, the WAG process can significantly increase the injection pressure and effectively seal the high-permeability layer through the Jamin effect to improve the degree of recovery. Moreover, for positive and reverse rhythm reservoirs of a certain thickness, the injection rate can be reduced according to the physical properties of the reservoir, and the gravity overburden phenomenon of the gas is used to achieve the effective development of the upper layers. The effect of the development of a positive rhythm reservoir therefore improved significantly. These findings provide data support for improving the development effectiveness of CO2 in low-permeability inhomogeneous reservoirs and emphasize the importance of the influence of multiple factors, such as injection flow rate, gravity, and rhythm, in CO2 replacement.

Effect of SDS Solutions on the Jamin Effect in a Capillary Tube with a Contracted Throat.

With the continuous exploitation of petroleum resources, the distribution and displacement of residual oils have become key issues in enhancing oil recovery. In a reservoir, there are various forms of residual oils caused by the capillary force, viscous force, and some other hydrodynamic effects, which lead to the Jamin effect, and they restrict the oil displacement process. In this study, the morphologies of oil droplets in a capillary tube laden with water and sodium dodecyl sulfate (SDS) solutions are experimentally investigated. The pinning behavior of the oil droplet is observed in the waterflood with a lower velocity, while depinning and rupturing behaviors occur at a higher velocity. Hereto, we build a mechanics model to analyze the evolution of the Jamin effect in a capillary tube with varying cross sections. Using this theoretical model, we obtain the two critical velocities for the depinning and rupture of the oil droplet, which agree with the experimental results. Moreover, we find that oil droplets can more easily pass through the entire capillary tube in SDS solutions compared with water. The time required for oil droplets to pass through the pore throat becomes shorter with the increase of SDS concentration. Therefore, a theoretical model is established to determine the total pressure difference and the minimum applied pressure difference. These findings are beneficial to obtain a deep insight into the detailed oil displacement and achieve a higher oil recovery rate.

A numerical feasibility study of CO2 foam for carbon utilization and storage in a depleted, high salinity, carbonate oil reservoir

Carbon Capture, Utilization, and Storage (CCUS) offers a viable solution to reduce the carbon footprint in the petroleum industry, and foam injection presents a promising method to achieve this while simultaneously increasing oil recovery. In this work, we studied the feasibility of CO2 foam for co-optimizing enhanced oil recovery and CO2 storage in a high-salinity carbonate formation. The simulated hydrodynamic model is a depleted formation containing 30% residual oil, with three mechanisms for CO2 storage: solubility, residual, and mineralization trapping mechanisms. The results showed that after 20 years, oil recovery during foam injection was 2.7 times higher than CO2 injection, and the CO2 stored during foam flooding was 38% higher than CO2 injection. Notably, foam injection also increased CO2 storage capacity by 2.6 times, indicating the potential to store around 2 gigatons of CO2 in the simulated model. This was attributed to the ability of foam to significantly reduce gas mobility and thus form isolated bubbles through its Jamin effect. Residual trapping was the dominant trapping mechanism, contributing to over 70% of the total CO2 trapped, attributed to the reduction in the dissolution of CO2 in brine due to the high salinity of the aqueous medium. CO2 mineralization was also studied, showing the least trapping efficiency and the dissolution trend of all the carbonate minerals. This study illustrates a novel CO2 utilization and storage technique in which CO2 is concurrently sequestered while enhancing oil recovery in a depleted oil reservoir by injecting CO2 as foam. The relevance of this study lies in its potential to provide a dual benefit of reducing greenhouse gas emissions and boosting oil production, offering a sustainable approach for the petroleum industry.

Numerical simulation of residual oil distribution characteristic of carbonate reservoir after water flooding

Carbonate reservoirs are characterized by abundant reserves and are currently focal points for development in oil and gas producing regions such as the Ahdab oilfield, Tarim Basin, Sichuan Basin, and Ordos Basin. The primary method for exploiting carbonate reservoirs is waterflooding. However, due to the complex pore structure and pronounced heterogeneity of carbonate rocks, the waterflooding process often leads to an unclear distribution of remaining oil and low waterflooding recovery efficiency, significantly impacting the stable and high production of carbonate reservoirs. This paper presents a two-phase flow model of oil and water in distinct pore structures by integrating fluid flow equations and interface tracking equations. It visually represents the waterflooding process at the pore scale, elucidates the distribution and formation mechanism of remaining oil, and discusses the mechanism of microscopic displacement efficiency change. The study reveals that: 1) After waterflooding, the distribution patterns of remaining oil can be categorized into dead-end remaining oil, pressure balance remaining oil, wall-bound remaining oil, Jamin effect remaining oil, and water-encapsulating remaining oil, which are governed by microscopic pore structure, wettability, and preferential flow paths; 2) From the perspective of actual reservoir displacement efficiency, intergranular pores > intergranular dissolved pores > visceral foramen > mould pore, with this trend being more pronounced under hydrophilic wetting conditions; 3) Given the oil-wet to strong oil-wet wettability characteristics of these carbonate rocks, capillary forces pose significant resistance during waterflooding. The conclusion underscores the importance of leveraging the reservoir’s microscopic pore structure and wettability characteristics for actual oil wells, elucidating the evolutionary law of the mechanical mechanism of oil-water interface advancement, clarifying oil-water percolation characteristics at the pore scale, and understanding the microscopic displacement physical mechanism, all of which are crucial for guiding the design of schemes aimed at enhancing reservoir recovery efficiency.

Study on Formation and Migration Law of Foam in Fractures and Its Influencing Factors.

This study focuses on the characteristics of foam generation, flow, and plugging in different reservoir fracture environments. Through visual physical model experiments and stone core displacement experiments, we analyze the flow regeneration of foam in a simulated reservoir fracture environment as well as its sealing and sweeping mechanisms. The findings reveal that low permeability reservoirs, with their smaller and more intricate fracture structures, are conducive to the generation of high-strength foam. This is due to the stronger shear effect of these fracture structures on the injected surfactant and gas mixture system, resulting in a denser foam system. Consequently, low permeability reservoirs facilitate a series of mechanisms that enhance the fluid sweep efficiency. Furthermore, the experiments demonstrate that higher reservoir fracture roughness intensifies the shear disturbance effect on the injected fluid. This disturbance aids in foam regeneration, increases the flow resistance of the foam, and helps to plug high permeability channels. As a result, the foam optimizes the injection-production profile and improves the fluid sweep efficiency. Stone core displacement experiments further illustrate that during foam flooding, the foam liquid film encapsulates the gas phase, thereby obstructing fluid channeling through the Jamin effect. This forces the subsequently injected fluid into other low-permeability fractures, overcoming the shielding effect of high-permeability fractures on low-permeability fractures. Consequently, this improves the fluid diversion rate of low permeability fractures, effectively inhibiting fluid cross-flow and enhancing sweep efficiency. These experimental results highlight the advantages of foam flooding in the development of complex reservoirs with low permeability fracture structures, demonstrating its efficacy in inhibiting fluid cross-flow and optimizing the injection-production profile.

Optimizing oil recovery with CO2 microbubbles: A study of gas composition

Microbubbles represent a feasible method for enhancing oil recovery (EOR). To further investigate microbubble displacement and interaction mechanisms between gas and oil, in this study, EOR experiments were conducted on normal (NB) and microbubble (MB) CO2 and CO2–N2 mixtures using NMR. The CO2 flooding process and the mechanism of microbubble CO2-oil interaction were examined, the contributions of small and large pores to oil recovery and CO2 storage were quantified. Importantly, economic benefits were analyzed under different injection conditions for the first time. The results show CO2 injection formed a stable displacement front and the maximum oil recovery was obtained from MB CO2. The oil swelling and “jamin effect” increased MB CO2 sweep area and the efficiency of small pore utilization was 20.9 % higher than NB CO2. Compared to CO2 injection, the oil recovery gradually decreased with increasing N2 concentration due to the reduced sweep area. The maximum CO2 storage efficiency achieved under MB CO2 injection was 35.92 %. Economic analysis revealed that MB CO2-EOR could provide significant economic benefits of approximately US $492.5 per ton of CO2 injected. This study provides data for the commercial application of microbubble technology.

Dynamic Simulation Research on Microprofile Control Mechanism of Foam in Fractured Media Based on Level Set Method.

Fractured reservoirs are an important source of oil and gas energy. After depletion of production, the production capacity of this reservoir decreases rapidly. Effective profile control is needed to improve the sweep efficiency and reservoir heterogeneity. Foam can solve such problems, but its profile control mechanism is not fully understood. Based on this, this paper uses the level set method to study the microscale control mechanism of foam in fractured media. The results show that artificial fractures and high-permeability microfractures are tighter than natural fractures, the Jamin effect of foam is stronger, and the secondary foaming ability is better. Therefore, the plugging ability of foam to natural fractures is far less than that of foam to artificial fractures and high-permeability microfractures. The larger the fracture opening, the larger the foam volume and the smaller the flow rate. As the opening ratio increases gradually, the generated foam flows more to the natural fractures with a large opening, and the effect of foam blocking large fractures becomes worse. The diversion rate curves of different opening ratios show that the foam has a good profile control effect when the opening ratios are 4:1 and 2:1, and even the diversion rate overturns, while the profile control diversion effect is poor when the opening ratio is 10:1, so it cannot play an effective role in profile control. The foam shows the profile control process of preferentially plugging the high-permeability area and allowing more subsequent fluids to enter the low-permeability area. The research reveals the profile control mechanism of foam on fractured reservoirs from the micro level, which is the supplement and verification of relevant macro research and provides a theoretical basis for the efficient development of fractured reservoirs.

Experimental study on the pseudo threshold pressure gradient of supported fractures in shale reservoirs

Pseudo threshold pressure gradient (PTPG) exists in the propped fractured reservoir, but its nonlinear flow law remains unclear. The effects of the mineral composition of shale and microstructure of fracturing fluid on PTPG were analyzed by X-ray diffraction and liquid nitrogen quick-freezing method. The results demonstrate that a proppant with a large particle size is more likely to form an effective flow channel and reduce liquid flow resistance, thus decreasing PTPG and increasing conductivity. The polymer fracturing fluid with rectangular microstructures significantly increased the PTPG supporting the fractured core. Experimental results show that the PTPG of the resin-coated sand-supported core in the fracturing fluid with a concentration of 1.2% is 245 times higher than that in the fracturing fluid with a concentration of 0.1% when the confining pressure is 5 MPa. Wetting hysteresis and the Jamin effect are responsible for the rise of PTPG in two-phase flow. The equivalent fracture width shows a good power function relationship with the PTPG. Thus, this study further explains the nonlinear flow behavior of reservoirs with fully propped fractures.

Interfacial chemical mechanisms of brine salinity affecting the CO2 foam stability and its effect on the sequestration capacity of CO2 in deep saline aquifer

CO2 foam flooding is an important method to expand the sweep scope of CO2 and significantly improve the ability of sequestrate CO2 in saline aquifer. Salinity is an important factor affecting the CO2 foam stability. In this study, it was found that the stability of CO2 foam prepared by alkyl polyglycoside APG-0810 was effectively improved by increasing the salinity. Molecular dynamics studies showed that increasing salinity promoted the adsorption of APG-0810 molecules at the CO2-water interface and enhanced the degree of inter-entanglement between alkyl chain segments, which dramatically increasing the CO2-water interfacial activity and liquid film strength. The enrichment degree of metal ions around the APG-0810 hydrophilic group also enhanced with the increase of salinity, which improves the disjoining pressure of the bubble liquid film. The binding ability of the hydrophobic groups of APG-0810 on CO2 molecules was enhanced, which inhibited the diffusion process of CO2 molecules inside the bubble. Subsequently, the influence rules of salinity on the CO2 foam rheology in the core were studied, and finds that increasing salinity increase the transition foam quality and the corresponding maximum viscosity. The improvement of liquid film strength reduces the probability of bubble aggregation inside the core, allowing a sufficient number of small-sized bubbles to be trapped by the pores, strengthening the superposition of Jamin effect and expanding the CO2 sweep scope in saline aquifer. In addition, we found that the zero-shear viscosity and yield stress of CO2 foam are positively correlated with salinity, which means that CO2 foam has a higher blocking ability for preferential channel for high-salinity saline aquifer, and the bubble cluster trapped by the capillary force will have a higher starting-pressure, improving the safety of CO2 sequestration in saline aquifer.

Study of gas-liquid two-phase flow characteristics in hydrate-bearing sediments

The characteristics of gas-liquid two-phase flow in hydrate-bearing sediments (HBS) are critical for natural gas hydrate production. This study experimentally investigates the flow patterns in the presence of hydrates and employs the phase field method for accurate simulations. Additionally, flow pressure differences in a capillary model were analyzed, and the impacts of occurrence patterns, saturation, and wettability of hydrates were investigated by numerical simulation. The results show that flow patterns are predominantly influenced by flow velocity. At high flow rates (Reynolds number >10), different gas-liquid ratios result in a variety of flow patterns, including annular, Taylor, and bubble flow. However, at lower flow rates (Reynolds number <10), the flow pattern consistently manifests as Taylor flow, regardless of gas-liquid ratio variations. Notably, the Jamin effect (a significant pressure differential caused by hydrates within the flow) was observed, which intensifies with increasing hydrate saturation and decreasing contact angle. Pore-filling hydrate patterns, in contrast to grain-coating, exhibit a greater number of gas-liquid interfaces, leading to larger pressure differences and a more evident Jamin effect. These findings aid in understanding the fluid migration in HBS and help estimate the natural gas production capacity.

Numerical analysis of drainage rate in multi-layer coalbed methane development in Western Guizhou, Southern China

In Western Guizhou, China, multi-layer development is a successful way for CBM development, with drainage rate control being the essential technology. In this article, a coupled hydraulic-mechanical numerical model considering permeability velocity-sensitive damage was established to analyze the impact of drainage rate on the gas production and reservoir parameters of multi-layer CBM development. The CBM development in the study area can be divided into four stages. The permeability velocity-sensitive damage and Jamin effect mainly occurred in the first two stages. Increasing the drainage rate during the first two stages will cause more serious permeability velocity-sensitive damage. Reducing the drainage rate in the first two stages could alleviate the permeability velocity-sensitive damage and Jamin effect. During the stable production stage II, the gas seepage being dominant in the c409 coal seam, the gas production would be significantly reduced under the permeability stress-sensitive damage as the drainage rate increasing. Based on the simulation results, three recommendations concerning the drainage rate optimization of multi-layer CBM development were advanced, and gas production was successfully improved. This study has important theoretical and practical significance for guiding the multi-layer CBM development in Western Guizhou and Southern China.

Simulation research on Jamin effect and oil displacement mechanism of CO2 foam under microscale

CO2 foam can solve the problems of serious water invasion in the later stage of water injection development of conventional reservoirs, fracture channeling in unconventional reservoirs and low production rate of medium and low permeability reservoirs caused by reservoir heterogeneity, and the Jamin effect is the key to its role. In order to investigate the influence of injection rate, liquid phase viscosity, surface tension, pore structure on the resistance of CO2 foam through the pore throat and the influence of CO2 foam Jamin effect on enhancing oil recovery, the micro-scale pore throat models were established, and the interface changes were traced by using the level set and phase field methods. The results show that the greater the injection rate or liquid phase viscosity, the greater the pressure and the foam film strength, the greater the Jamin effect resistance; Jamin effect resistance is positively related to surface tension, the greater the surface tension, the greater the driving force required for difficult deformation; Jamin effect resistance is negatively related to radius of pore throat, the greater the radius of pore throat (the smaller the pore-throat ratio), the smaller the Jamin effect resistance; CO2 foam plays an important role in the oil displacement, and it can displace the oil trapped on the wall, and the oil recovery of CO2 foam flooding is 9% higher than that of water flooding. The smaller the oil–water interfacial tension is, the more CO2 foam displacement is. These research results have certain theoretical significance for the effective use of CO2 foam in oilfield development.

Investigation of the plugging capacity and enhanced oil recovery of flexible particle three-phase foam

In the later stage of water flooding in reservoirs, the oil production decreases. The stability of three-phase foam system is strong, enhancing oil displacement effects of ultrahigh water cut reservoirs. In this paper, the flow state of the foam system was studied by using a microscopic visualization model. Second, sandpack flooding experiments were performed to analyze the optimal plugging conditions of three-phase foam through resistance factors. Finally, single and parallel sandpack flooding experiments were carried out to analyze plugging effect and production conditions under different injection systems and permeability ratios. The research shows that three-phase foam is more stable and capable of plugging. The stable residual resistance factor after injection of the three-phase foam system is 172.75. When the foam and particles are injected simultaneously, the gas–liquid ratio is 1:1, the formation permeability is 5526.5 mD, and the plugging effect of three-phase foam is the best. The oil recovery increases by 24.9% after the injection of three-phase foam system. The three-phase foam system combines Jamin effect of foam and dynamic plugging characteristics of flexible particles. The highest oil recovery factor of 80.87% is achieved at a permeability ratio of 9.99. Three-phase foam flooding has broad application prospects.

Experimental study on fluid flow behaviors of waterflooding fractured-vuggy oil reservoir using two-dimensional visual model

The carbonate reservoir plays a pivotal role in conventional oil and gas reservoirs. However, due to limited knowledge of fluid flow characteristics in fractured-vuggy carbonate formations (vuggy means a small to medium-sized cavity inside rock), high efficiency reservoir development remains challenging. In this study, the similarity principle is utilized to design a two-dimensional visual model based on geological data and the injection-production characteristics of a fractured-vuggy reservoir in M Oilfield. To investigate the characteristics of oil–water flow, the oil–water interface, and residual oil distribution, flooding experiments are conducted at various injection-production positions, types, and injection rates. The results suggest that a low injection/high production strategy is optimal for achieving maximum oil recovery. As a consequence, this configuration is employed in the subsequent flooding experiments. The optimal oil recovery of 82.2% is attained via pore injection and vug production. The Jamin effect exerts an influence on the oil-water flow in structures connected by small channels at the bottom of large vugs, necessitating adjustment of the flow rate to achieve optimal injection conditions. The variation of the oil–water interface height in each vug due to structural flaws results in suboptimal overall oil recovery. The oil recovery is limited to approximately 30% at an injection rate below 8 ml/min but can be enhanced to over 70% with a higher injection rate exceeding 8 ml/min. The residual oil of the fractured-vuggy reservoir is typically found in the tops of structures and peripheral areas with poor connectivity. The findings of this study offer direction for optimal production in fractured-vuggy carbonate reservoirs and facilitate a more comprehensive comprehension of oil–water flows within the reservoir.

Experimental Study on the Forcible Imbibition Law of Water in Shale Gas Reservoirs

Water imbibition is a key factor affecting the flowback regime of shale gas wells after volume fracturing. In this study, a set of experimental apparatus and corresponding test and evaluation methods were developed to analyze the laws of forcible imbibition of water in a shale reservoir, characterize the initiation time of microfractures induced by shale hydration quantitatively, and optimize the shut-in time of shale gas wells; the imbibition depths of different pore types are quantitatively calculated based on the multiple pore imbibition analytical model. The experimental results show that: according to imbibition saturation growth rate, the shale forcible imbibition can be divided into three periods, imbibition diffusion, imbibition transition, and imbibition balance. Among them, the imbibition diffusion period is the main period for imbibition capacity rise. The reason for this phenomenon is that due to the fluid pressure difference effect, the shale fills its large pores and microfractures rapidly in the early stage, and in the percolation transition period, the percolation rate decreases continuously due to the gradual increase of fluid saturation. Due to the Jamin effect, it is difficult for the fluid to enter the small pores and the fluid fills the pore roar channel, the seepage saturation tends to stabilize, and the seepage equilibrium period appears. In the early period of shut-in, the imbibition capacity of shale increases significantly under the action of fluid pressure, providing a large amount of imbibition fluid for the spontaneous imbibition later. The imbibition depth of a clay pore was much greater than that of a brittle mineral pore and an organic pore. The reservoir confining pressure has prohibition on shale imbibition, but even under reservoir confining pressure, imbibition can still improve the fracturing effect of the reservoir, resulting in an increase in porosity of 0.42–1.63 times and an increase in permeability of 17.6–67.3 times. Under the experimental conditions, the initiation time of induced microfractures is 98.5 h on average and is in negative correlation with imbibition capacity. On this basis, the optimized shortest shut-in time of a shale gas well is 5 days. The study results can provide a scientific basis for the optimization of the flowback regime of shale gas reservoirs.

Investigation of Fracturing Fluid Flowback in Hydraulically Fractured Formations Based on Microscopic Visualization Experiments

Fracturing fluids are widely applied in the hydraulic fracturing of shale gas reservoirs, but the fracturing fluid flowback efficiency is typically less than 50%, severely limiting the shale gas recovery. Additionally, the mechanism and main influencing factors of fracturing fluid flowback are unclear. In this study, microscopic experiments are conducted to simulate the fracturing fluid flowback progress in shale gas reservoirs. The mechanism and factors affecting fracturing fluid flowback/retention in the fracture zone were analyzed and clarified. Results show that the ultimate flowback efficiency of fracturing fluid is positively correlated with the fracturing fluid concentration and the gas driving pressure difference. There are four kinds of mechanisms responsible for fracturing fluid retention in the pore network: viscous resistance, the Jamin effect, the gas blockage effect and the dead end of the pore. Additionally, the ultimate flowback efficiency of the fracturing fluid increases linearly with increasing capillary number. These insights will advance the fundamental understanding of fracturing fluid flowback in shale gas reservoirs and provide useful guidance for shale gas reservoirs development.

Methane Hydrate Dissociation in Quartz Sand by Depressurization Combined with Microwave Stimulation

Depressurization combined with thermal stimulation is a promising method for gas hydrate production. Owing to its advantages of rapid uniform heating, microwave radiation is an efficient source of heat. However, the mechanisms of hydrate decomposition under depressurization combined microwave stimulation are currently unclear. In this study, methane hydrate was synthesized under 6 MPa and 2 °C, with hydrate saturation of approximately 42% in natural quartz sand. We then compared hydrate decomposition via rapid depressurization and piecewise depressurization, with or without microwave stimulation at 2.45 GHz and 400 W. When using the depressurization method alone, the hydrate decomposition rate increased with the depressurization amplitude. However, in the last stage of hydrate decomposition, the external flow of gas was hindered by the Jamin effect, especially under larger depressurization amplitudes; therefore, extremely low production pressure is not justified. When combined with microwave stimulation, both depressurization methods resulted in increased reservoir temperature within a few seconds, and microwave heating provided an extra driving force for hydrate decomposition. Furthermore, microwave heating was more effective when larger amounts of undecomposed hydrate remained after depressurization. When depressurization was combined with microwave stimulation, the average gas production rate at 100% gas production was 0.269–0.601 L/min, which was significantly higher than that for depressurization alone. However, the energy efficiency ratio was approximately 1, which has no practical value. Conversely, the average gas production rate at 90% gas production was 0.452–2.945 L/min and the energy efficiency ratio was 2.9–17.6. Under the combined method, gas hydrate decomposition at a production pressure of 1.9 MPa achieved the subtle balance between the average gas generation rate and energy efficiency. Thus, optimizing the gas production pressure and microwave stimulation time can improve the average gas production rate and energy efficiency ratio according to the reservoir hydrate conditions.

Effect of wettability on oil and water distribution and production performance in a tight sandstone reservoir

Wettability is an important factor that dominates the micro-distribution of initial oil and water, residual oil, and subsequent oil recovery in a tight oil reservoir. In this paper, integrated experimental techniques have been developed to examine the effect of wettability on oil and water micro-distribution together with production performance in a tight reservoir. Wettability alteration indicated by contact angles during the aging process was firstly monitored and measured continuously. Then, nuclear magnetic resonance (NMR) measurements were integrated with rate-controlled mercury injection (RMI) tests to determine pore and throat size distribution. Subsequently, NMR measurements were performed to not only characterize the oil and water distribution in the process of wettability change, but also evaluate the production performance and recovery potential. Furthermore, displacement experiments were carried out to visually observe the microscopic distribution of residual oil under different wettability conditions. For a strong water-wetting rock, oil is separated from the surface of a pore/throat on which a thin water film is adsorbed, and then fills the center of the pore in the form of oil droplets. The displacement experiments show that water saturation of a two-phase flow zone on relative permeability curves ranges from 22.5% to 55.1% and that water saturation at the isotonic point is 43.6% with its waterflooding oil recovery of 42.1%. For a weak oil-wetting rock, oil is mainly distributed in porous media in the form of an oil film. The water saturation of a two-phase flow zone ranges from 22.3% to 48.1%, while that of the isotonic point is 38.1% with waterflooding oil recovery of 33.2%. With wettability altering from strong water-wetting to weak oil-wetting, oil either is adsorbed on the pore and throat surface or migrates from the center of a larger pore to a smaller pore and/or throat. It is more unfavorable to the seepage of oil due to the fact that the two-phase flow zone is narrowed and a decrease in water saturation at the isotonic point, leading to a lower waterflooding oil recovery. After waterflooding, oil droplets caused by the Jamin effect, oil clusters resulted from heterogeneity, and small oil droplets dispersed at the corner of a pore are visually observed in cores with strong water-wetting. Within weak oil-wetting cores, residual oil is mainly distributed in a membrane-like form due to adsorption and oil clusters resulted from heterogeneity.