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CO2 injection has become one of the most important methods of enhanced oil recovery in tight reservoirs， but some hydrocarbon gases have more viscosity-reducing and miscibility on oil compared to pure CO2. Therefore， this article studied the saturation pressure and viscosity changes of oil with CO2 and composite gas （CO2 and C2H6） by PVT experiments at high-temperature and high-pressure and revealed the percentage of producing oil with different gases， huff and puff pressures， and rounds by core huff and puff experiments at high-temperature and high-pressure. The results show that the C2H6 in the composite gas enhances the gas and liquid miscibility， improves the CO2 viscosity reduction and dissolution ability， and significantly increases the fluidity of oil. With the increase of C2H6 mole fraction in the composite gas， the saturation pressure of oil increases by 26.54% from 14.24 MPa to 18.02 MPa， and the viscosity of crude oil decreases from 23.68 mPa·s to 8.76 mPa·s. Under different huff and puff pressures， the oil recoveries of composite gas （CO2 and C2H6） are better than that of pure CO2， and the increase of recovery near the minimum miscibility pressure is higher than under other huff and puff pressures. The percentage of producing oil by composite gases is higher than that of pure CO2 in the pores of 0.0001-0.001 μm and 0.01-1 μm.

The laminated structure of continental shale oil reservoirs introduces significant macro and micro heterogeneity, posing challenges for efficient shale oil extraction. Existing microscopic experimental and simulation methods are insufficient to accurately simulate the fluid flow behavior in mud–lime interactive laminated shale reservoirs. This study delves into the complexities of laminated shale reservoirs with a focus on their heterogeneous structure and wettability. Using scanning electron microscopy, we extracted the structural features of laminated shale reservoirs and established a Multicomponent and multiphase -multi relaxation time-Lattice Boltzmann model(MCMP-MRT-LBM) that considers nanoscale effects such as wall adsorption, liquid–solid slippage, and liquid–liquid slippage. We investigated the occurrence state, the flow behavior, and the phase seepage characteristics of crude oil in laminated shale at different water saturation stages and explored the reasons behind interlayer channeling and the conditions under which crude oil is mobile within limestone and mudstone layers. Then, we examined the impact of varying factors, including heterogeneous wettability, displacement pressure gradients, and pore size, on relative permeability, water injection capacity, sweep efficiency, and crude oil recovery in laminated reservoirs. The results indicate that wettability and pore size distribution, driven by capillary and viscous forces, dictate the occurrence state of remaining oil. Wettability primarily influences fluid distribution, whereas pore size distribution substantially impacts fluid morphology. It also highlights the pivotal role of flow velocity differences between layers in causing interlayer channeling. Increasing the capillary number promotes crude oil mobility within mudstone layers, with the initiation pressure gradient in mudstone layers being 2.5 times that of the limestone layer. The examination of the oil–water relative permeability reveals the dominance of pressure gradients in affecting oil flow capabilities, while pore size significantly influences water flow capacity. By optimizing various factors, it is possible to enhance water injection capacity and sweep efficiency, resulting in a substantial 5%–10% increase in crude oil recovery from laminated shale reservoirs. [ABSTRACT FROM AUTHOR]

Natural Gas Hydrate (NGH) has attracted increasing attention for its great potential as clean energy in the future. The main heat transfer mode that controls the thermal front movement in the process of NGH exploitation by heat injection was discussed through NGH thermal stimulation experiments, and whether it is reliable that most analytical models only consider the heat conduction but neglect the effect of thermal convection was determined by the comparison results between experiments and Selim’s thermal model. And the following findings were obtained. First, the movement rate of thermal front increases with the rise of hot water injection rate but changes little with the rise of the temperature of the injected hot water, which indicated that thermal convection is the key factor promoting the movement of thermal front. Second, the thermal front movement rates measured in the experiments are about 10 times that by the Selim’s thermal model, the reason for which is that the Selim’s thermal model only takes the heat conduction into account. And third, theoretical calculation shows that heat flux transferred by thermal convection is 15.56 times that by heat conduction. It is concluded that thermal convection is the main heat transfer mode that controls the thermal front movement in the process of NGH thermal stimulation, and its influence should never be neglected in those analytical models.

Hydrate reservoirs in the South China Sea belong to muddy silt‐type hydrate reservoirs with low permeability. Horizontal well fracturing is one of the main stimulation methods for low‐permeability oil and gas reservoirs. For muddy silt‐type hydrate reservoirs, the stability and effectiveness of hydraulic fractures may be a severe problem due to poor reservoir cementation, reservoir deformation, and sand production. In this paper, the time variability of fracture conductivity is considered for the first time. According to the geological data at offshore gas hydrate production test site in the South China Sea, a multilayer hydrate reservoir model was established, and the influence of the time variable fracture conductivity on the production behavior in the process of horizontal well fracturing was analyzed. The simulation results show that, compared with the case of constant fracture conductivity, the gas production rate with the case of time variable fracture conductivity is greatly reduced, and the 5‐year cumulative gas production is reduced by 49.9%. Sensitivity analysis shows that the larger the initial fracture conductivity, the higher the peak gas production rate; the larger the attenuation magnitude of the fracture conductivity, the lower the gas production rate in the late production period; the larger the decline rate coefficient of the fracture conductivity, the higher the gas production rate in the early production period. The analysis of the orthogonal experimental design shows that the influence of the attenuation magnitude of fracture conductivity, the initial conductivity of fracture, and the decline rate coefficient of fracture conductivity on the cumulative gas production decreases in order. The actual production process should try to avoid excessive attenuation magnitude of fracture conductivity, while improving the initial fracture conductivity as much as possible to ensure high cumulative gas production. [ABSTRACT FROM AUTHOR]

The CO2-crude oil miscible zone is the key factor to improve the recovery of miscible flooding, and the migration behavior of CO2-crude oil miscible zone has an significant influence on the development effect of CO2 miscible flooding. At present, the research on the characteristics of CO2-crude oil miscibility mainly focus on the miscible mechanism and the migration behavior of the miscible front edge, but there still remain many gaps in the systematic studies on the migration behavior of miscible zones. This paper defines four characteristic parameters of the miscible zone and presents the migration behavior of the miscible zone through theoretical analysis and numerical simulation. The results demonstrate that before the miscible zone's front edge breaks through, the front and rear edges' sweep coefficient and the dimensionless miscible zone's area increase linearly.Then, the dimensionless miscible zone's width decreases gradually after reaching the local maximum, while the front and rear edges' fingering coefficient increase more and more rapidly. After the miscible zone's rear edge breaks through, the miscible zone sweep coefficient's increase rate dropped significantly. The dimensionless miscible zone's area, the dimensionless miscible zone's width and the fingering coefficient gradually decrease and then stabilize. Based on the accurate characterization of miscible zone, it can provide a basis for the miscible zone regulation to improve the development effect of CO2 flooding. [ABSTRACT FROM AUTHOR]

There are obvious differences in the effective production conditions and recoverability evaluation methods between shale oil and gas and conventional oil and gas. In order to investigate the seepage characteristics of shale oil in micro and nano pores, low-velocity seepage experiment was conducted to study the low-velocity non-Darcy seepage patterns of single-phase fluids in Qianjiang Sag, Jiyang Sag and Eagle Ford reservoirs in typical shale blocks at home and abroad. The results of the study showed that the low-rate seepage characteristics of shale oil were mainly affected by the liquid-solid boundary layer effect, slip length and seepage channel. The seepage curve of Qianjiang Sag was concave. The smaller the pressure gradient, the stronger the fluid-solid interface force, and the more obvious the non-linear section; Jiyang Sag was obviously affected by the development of rock core microfractures, and big pores such as inorganic pores and microfractures were the main flow channels at low pressure gradients, with low surface roughness and tortuosity; as the pressure gradient increased, fluid flowed in the small pores and organic pores; Eagle Ford reservoirs were influenced by the mineral composition and pore structure of the block, and the seepage characteristics presented two linear sections with different slopes, and the resistance to seepage increased as the pressure difference increased. The study clarifies the main characteristics and influencing mechanisms of low-velocity seepage of shale oil in nano and micron pores, providing a theoretical basis for formulating shale oil development plans and guiding the efficient development of shale oil. [ABSTRACT FROM AUTHOR]

Shale reservoirs are characterized by low porosity and low permeability, and volume fracturing of horizontal wells is a key technology for the benefits development of shale oil resources. The results from laboratory and field tests show that the backflow rate of fracturing fluid is less than 50%, and the storage amount of fracturing fluid after large-scale hydraulic fracturing is positively correlated with the output of single well. The recovery of crude oil is greatly improved by means of shut-in and imbibition, therefore attracting increasing attention from researchers. In this review, we summarize the recent advances in the migration mechanisms and stimulation mechanisms of horizontal well high pressure forced soaking technology in the reservoirs. However, due to the diversity of shale mineral composition and the complexity of crude oil composition, the stimulation mechanism and effect of this technology are not clear in shale reservoir. Therefore, the mechanism of enhanced oil recovery by imbibition and the movable lower limit of imbibition cannot be characterized quantitatively. It is necessary to solve fragmentation research in the full-period fluid transport mechanisms in the follow-up research. [ABSTRACT FROM AUTHOR]

Sand production has become a common phenomenon in the exploitation of unconsolidated natural gas hydrate reservoirs, which will hinder the long-term production of natural gas hydrate reservoirs. However, there are few literatures reported on the influences in reservoir physical properties such as permeability and porosity, and production laws caused by sand production. This paper provides a numerical model, coupled with reservoir sand-gas-water multiphase flow processes, which is capable to simulate the process of sand production in natural gas hydrate reservoirs. The simulation results indicate that sand settlement is mainly concentrated near the wellbore due to the high concentration of migrated sand. The decrease in reservoir porosity and permeability caused by sand settlement has a significant impact on production. The impact of sand production on reservoir fluid fluidity shows that fluid flow is inhibited near the wellbore, while fluid flow performance increases far away from the wellbore. The numerical model and analysis presented here could provide useful insight into changes in reservoir physical properties and production laws caused by sand production in the natural gas hydrate-bearing marine sediments using depressurization method. [ABSTRACT FROM AUTHOR]

The difficulty of deploying remaining oil from unconventional reservoirs and the increasing CO2 emissions has prompted researchers to delve into carbon emissions through Carbon Capture, Utilization, and Storage (CCUS) technologies. Under the confinement of nanopore in unconventional formation, CO2 and hydrocarbon molecules show different density distribution from in the bulk phase, which leads to a unique phase state and interface behavior that affects fluid migration. At the same time, mineral reactions, asphaltene deposition, and CO2 pressurization will cause the change of porous media geometry, which will affect the multiphase flow. This review highlights the physical and chemical effects of CO2 injection into unconventional reservoirs containing a large number of micro-nanopores. The interactions between CO2 and in situ fluids and the resulting unique fluid phase behavior, gas-liquid equilibrium calculation, CO2 adsorption/desorption, interfacial tension, and minimum miscible pressure (MMP) are reviewed. The pore structure changes and stress distribution caused by the interactions between CO2, in situ fluids, and rock surface are discussed. The experimental and theoretical approaches of these fluid-fluid and fluid-solid reactions are summarized. Besides, deficiencies in the application and safety assessment of CCUS in unconventional reservoirs are described, which will help improve the design and operation of CCUS. [ABSTRACT FROM AUTHOR]

CO2-alternating-water injection is an effective way of enhancing recovery for low-permeability oil reservoirs. The injection process is one of the essential issues that are facing severe challenges because of the low permeability and poor pore space connectivity. Previous researchers mentioned that water injection ability could be decreased by around 20% after the CO2-flooding; hence, it is necessary to quantify the water injectivity variation during an alternated injection process. In this paper, a CO2 convection-diffusion model is established based on the seepage law of CO2 and dissipation effect. The relationship between the width of miscible flooding and injection time is defined. Besides, an equivalent resistance method is introduced for developing a capillary bundle model for featuring an unequal diameter for CO2 water vapor alternate flooding. CO2-oil and CO2-water interactions are analyzed using the new model. The effects of oil viscosity, pore throat ratio, CO2 slug size, and equivalent permeability of the capillary bundle on water injection are analyzed. The result indicates that water injection ability increases with the rise of CO2 slug size and equivalent permeability of the capillary bundle and decreases with the increase of viscosity and pore throat ratio. [ABSTRACT FROM AUTHOR]

A novel predictive model for calculating relative permeability was derived based on a capillary tube model with fractal theory. Different forms of immovable water including water film (WF) and microcapillary water were incorporated in the new model. Special immovable water called lost dynamic water (LDW) was introduced in the proposed model. The results of verification show that there is agreement between the calculated results and the published experimental data and analytical model. The results indicated that the effect of LDW, WF, and stress dependence had a significant influence on the relative permeability, which cannot be neglected. A larger LDW coefficient, more dead-end pores, and corners in porous media yielded a more complex pore structure. Therefore, more water was trapped in the pore and became connate water, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. Due to the microcapillary effect, the relative permeability of the water/gas increased/decreased as the drawdown pressure increased at the same water saturation. Higher effective stress was more likely to cause rock deformation, resulting in higher gas relative permeability and lower water relative permeability at a given water saturation. This study provides a significant reference for reservoir engineers conducting water and gas two-phase flow analysis. The theoretical model is beneficial for research into the interpolation of relative permeability via numerical simulation. [ABSTRACT FROM AUTHOR]

Multiple hydraulic fractures in naturally fractured unconventional shale reservoirs have often induced complicated fracture network expansion, as revealed by micro-seismic fracture mapping. As productivity of conventional energy resources decreases and the proportion of reserves in unconventional oil/gas increases, the theoretical method about the modeling and simulation of complex fracture network propagation needs to be improved to innovate stimulated reservoir volume (SRV) fracturing technology. To simulate the fracture network growth, a new model based on the modified displacement discontinuity method (MDDM) coupling pseudo-3D fracture propagation model is proposed introducing the propagation pattern and criterion. The numerical result of this model is solved and the process of fracture network propagation is simulated in different natural fracture (NF) distribution and fracturing parameters. The effects of NF distribution, hydraulic fracture (HF) spacing, bottomhole pressure and segmented and multi-cluster fracturing mode on the fracture network propagation are discussed. The simulation results of complex fracture network are characterized by four parameters as well. The results show that there are reasonable fracturing parameters technically during the SRV fracturing in unconventional shale reservoirs. It is significant to reasonably and efficiently develop the unconventional shale resources by researching the fracture network propagation rules. [ABSTRACT FROM AUTHOR]

CO2 capture and reinjection process (CCRP) can reduce the used CO2 amount and improve the CO2 storage efficiency in CO2 EOR projects. To select the best CCRP is an important aspect. Based on the involved equipment units of the CCRP, a novel techno-economic model of CCRP for produced gas in CO2 EOR and storage project was established. Five kinds of CO2 capture processes are covered, including the chemical absorption using amine solution (MDEA), pressure swing adsorption (PSA), low-temperature fractionation (LTF), membrane separation (MS), and direct reinjection mixed with purchased CO2 (DRM). The evaluation indicators of CCRP such as the cost, energy consumption, and CO2 capture efficiency and purity can be calculated. Taking the pilot project of CO2 EOR and storage in XinJiang oilfield China as an example, a sensitivity evaluation of CCRP was conducted based on the assumed gas production scale and the predicted yearly gas production. Finally, the DRM process was selected as the main CCRP associated with the PSA process as an assistant option. The established model of CCRP can be a useful tool to optimize the CO2 recycling process and assess the CO2 emission reduction performance of the CCUS project. [ABSTRACT FROM AUTHOR]

The seepage behavior in shale oil reservoir is very complicated. In this study, the characteristics and influencing factors of low-velocity seepage in brittle shale oil reservoirs were investigated by high precision experimental methods. The velocity used in this study was as low as 10−4 ml/min, and at least eight different flow rates were measured for each experiment. During the operation, the pressure difference between the inlet and outlet was controlled within 0.35 MPa to eliminate the influence of stress sensitivity. The effects of core permeability, fluid viscosity, pore pressure, and propped artificial fracture on the seepage behavior were analyzed. The results show that the seepage flow rate and pressure gradient in shale core samples presents a convex relationship, which is entirely different from the results of a concave relationship in tight sandstone oil reservoirs. The slippage effect and boundary layer effect in the flow channels were investigated to explain the convex flow regime theoretically. The convex shape flow regime is caused by the heterogeneous of shale core samples associated with the completed developed micro-fractures in this area. The seepage flow divides into two stages: the non-linear stage when the applied pressure gradient is lower than 2 MPa/m and the linear stage when it is higher than 2 MPa/m. The non-linear seepage characteristics become more obvious with a higher viscosity crude oil. With the increase of pore pressure, micro-fractures in shale core samples gradually close, leading to the reduction of flowing channel and the significant decrease of apparent permeability. The seepage characteristics are similar to those of tight sandstone oil, and the flow rate and pressure gradient curve presents a concave shape. With a propped artificial fracture, the seepage flow behavior follows Darcy's law. This work provides a feasible and reliable method and valuable experiment data for the study of low-velocity seepage in shale reservoirs. • A high-precision seepage flow apparatus was applied, and a series of low-velocity flow experiments were performed. • The characteristics and laws of low-velocity seepage in shale reservoirs were discussed in detail for the first time. • The convex shape relationship of the seepage flow rate and pressure gradient were discovered and explained theoretically. • The effects of core permeability, fluid viscosity, and propped artificial fracture on the seepage behavior were analyzed. [ABSTRACT FROM AUTHOR]

In this study, Huff-n-Puff (HnP) experiments were conducted to investigate the potential for producing hydrocarbons from the shale core samples using CO 2 HnP and N 2 HnP, respectively. The compositions of crude oil, produced oil, and gas in the system were analyzed by Gas Chromatography/Mass Spectrometer (GC/MS). The results showed that at the end of six injection cycles, the cumulative oil recovery factors were 61.49% for CO 2 injection and 34.85% for N 2 injection. CO 2 had better injectivity in the ultra-low permeability shale cores than N 2. The injected gas extracted and vaporized the light hydrocarbon components C 3-8 into the gas phase. After six HnP cycles, the recovery factors of C 3-4 were 91.6% for CO 2 HnP and 75.1% for N 2 HnP. For the other components, the recovery factors were about 60% for CO 2 HnP and 30% for N 2 HnP. After that, a core scale model was established to mimic the process of HnP and the mechanisms leading to the different performances of CO 2 HnP and N 2 HnP were discussed. Different properties relating to the EOR mechanisms during HnP process were investigated. The results indicated that a significant amount of CO 2 could dissolve into the crude oil and deposit as free gas phase existing in the core. During the CO 2 HnP process, the oil and gas interfacial tension reduced to zero, and the oil viscosity was reduced by 40%–60%. The gas cap drive, dissolved gas drive, and miscible drive during CO 2 HnP are more efficient than that during N 2 HnP. The change of the molecular diffusion rate resulted in an obvious change in oil recovery factor. Although simultaneous CO 2 and N 2 is still improving the recovery, pure CO 2 shows the best result. This study provides operators with valuable laboratory data about the produced hydrocarbon analysis on CO 2 HnP and N 2 HnP in shale oil production and a better understanding of gas HnP mechanisms. • The cumulative oil recovery, injected gas quantity, produced hydrocarbon components were measured during HnP experiments. • The mechanisms referring to the different performance of CO 2 HnP and N 2 HnP were discussed. • The light oil components C 3-8 was vaporized into gas phase and the heavy components were produced in oil phase. • CO 2 has higher injectivity, higher solubility, and lower propel effect than N 2. [ABSTRACT FROM AUTHOR]