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This paper investigates the CO2/N2 injection process in tight oil reservoirs considering the confinement effect. To study the microscopic physical mechanisms, the confinement effect is characterized by properties shift and capillarity and introduced into the flash calculation to obtain the phase equilibrium of mixture fluids (tight oil/CO2/N2) in tight porous media. The results indicate that the injected nitrogen gas could effectively maintain the reservoir pressure, while it also weakens the effects of the CO2 injection recovery mechanisms, notably diffusivity and viscosity reduction. In addition, a dual‐pore tight oil reservoir model is set up to investigate the CO2/N2 injection with ultra‐low permeability and hydraulic fracturing. The basic CO2 injection parameters are optimized by the orthogonal method. Based on CO2 injection process, three injection schemes of CO2/N2 injection, which are mixed‐gas injection, CO2‐alternating‐N2 (CAN) injection, and N2‐alternating‐CO2 (NAC) injection, were investigated and a comparative analysis was made for the pressure distribution, CO2 mole fraction distribution, and cumulative oil production. Based on this analysis, the CAN injection process proved to be the best injection scheme. A parametric analysis further suggested that the nitrogen gas injection rate was the most important factor. Besides, the effect of gravity drainage, reservoir permeability, nature fractures, and permeability heterogeneity on the oil production of CAN injection process were also investigated in detail. The results show that tight oil reservoir with better vertical connectivity, poor fracture growth, and higher heterogeneity is more favorable for the CO2/N2 injection process.

The phase equilibria with the confinement effect could shift in nano‐pores, which could have a great impact on the recovery mechanisms of CO2 injection in tight oil reservoirs; this has not been systematically studied. In this paper, the confinement effect with property shift and capillarity effect is introduced into the flash calculation of confined fluids. The Soave modification of the Redlich–Kwong equation of state is extended by the molecular‐wall collision parameter to describe the shifted pressure–volume–temperature properties of confined fluid, and the Young–Laplace equation is applied to evaluate the capillary pressure. This developed model could effectively be applied for phase equilibrium calculation in tight porous media because of the verification of experimental results. A binary mixture is investigated to study the different effect of capillary pressure and property shift on phase equilibria. Subsequently, a typical hydrocarbon fluid from Middle Bakken tight oil reservoirs is studied with CO2 injection. Results illustrate that the confinement effect could play an increasingly important part in the phase equilibrium state. The CO2 solubility and mass transfer driving force in tiny pores would be greater than those in large pores under the same conditions. The gas phase saturation would be smaller with the same compositions, which could extend the single‐phase region of fluid flow in porous media. Furthermore, bubble‐point pressure, the minimum miscible pressure of CO2/hydrocarbon, and the viscosity of tight oil dissolved with CO2 both decrease with the pore size, which has a good influence on tight oil recovery. In general, the confinement effect could effectively reinforce the recovery mechanisms of CO2 injection, which is conducive to the enhancement of tight oil recovery. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Modeling oil flow confined in nanoscale pores is the preliminary and foundation of nonlinear seepage research of tight reservoirs. In this study, an analytical nanohydrodynamic model for the description of flow characteristics of confined oil in nanoscale pores with diameters greater than 2 nm is proposed coupling with viscosity distribution function and slip velocity model based on the liquid–solid intermolecular force mechanisms. This analytical model has been validated by experimental results. Analysis results of this model reveal the special flow characteristics of tight oil confined in nanopores: the velocity profile curve on the cross section is coupled parabolic with exponential line, and the maximum velocity in center is related to pore size and liquid–solid interaction strength. Furthermore, the thickness of the low-velocity region near the wall, which reflects the action scope of pore surface, could be quantified by this model. The critical radius of the nanopore to distinguish the confined flow and unconfined flow is determined by this model, which would increase with a decrease in the liquid–solid interaction strength. And the non-Darcy seepage mechanisms of tight reservoirs could be revealed by this model because of the consistent characteristics of flowrate curve and non-Darcy flow curve. Besides, increasing temperature could weaken the confinement effect and changing wettability is an effective method to enhance tight oil mobility. Finally, apparent permeability is derived for tight reservoirs from this nanohydrodynamic model.

The fault-karst carbonate reservoir is a new type of deep carbonate oil and gas resource and a target for exploration and development. The distribution of remaining oil in this kind of oilfield is very complicated because of its unique reservoir characteristics of vertical migration and accumulation, segmented accumulation, and differential accumulation. Therefore, the S91 reservoir block, a typical fracture-vuggy carbonate reservoir in the Tahe oilfield, was taken as the object of this research. According to the development characteristics as well as the porosity and permeability characteristics of the fracture-vuggy, the reservoirs were divided into three types: cave, pore, and fracture. A numerical simulation model of the fracture-vuggy reservoir of the S91 unit was established, and the historical fitting accuracy with dynamic production data was more than 90%. Then, the distribution characteristics of the remaining oil in the depletion stage of the fault-karst carbonate reservoir were further studied and based on the analysis of the reservoir water-flood flow line, the remaining oil distribution characteristics in the depletion stage of the fault solution reservoir were revealed. The results show that the remaining oil distribution patterns during the depletion production stage can be divided into three types: attic type, bottom water coning type, bottom water running type. Due to the serious problem of the bottom aquifer lifting caused by the reservoir development, the residual oil between wells was relatively abundant during the depletion production stage. According to the simulation results, the remaining oil distribution modes in the water drive development stage were identified as three types: sweeping the middle between wells, bottom water connection and circulation, and oil separation through high-permeability channels. In addition, the reservoir connectivity was the main controlling factor for the remaining oil distribution in the fault-karst carbonate reservoir.