Tight oil has been effectively developed thanks to artificial fracture technology. The basic mechanism of effective production through fractures lies in the contact between the fractures (both natural and artificial) and the matrix. In this paper, the natural tight cores from J field in China are used to conduct experimental studies on the different fluid huff-‘n-puff process. A new core-scale fracture lab-simulation method is proposed. Woven metallic wires were attached to the outer surface of the core to create a space between the core holder and core as a high permeable zone, an equivalent fracture. Three different injecting fluids are used, including CO₂, N₂ and water. The equivalent core scale reservoir numerical models in depletion and huff-n-puff mode are then restored by numerical simulation with the Computer Modeling Group—Compositional & Unconventional Reservoir Simulator (CMG GEM). Simulation cases with eight different fracture patterns are used in the study to understand how fracture mechanistically impact Enhanced Oil Recovery (EOR) in huff n puff mode for the different injected fluids. The results showed: Firstly, regardless of the arrangement of fractures, CO₂ has mostly obvious advantages over water and N₂ in tight reservoir development in huff-‘n-puff mode. Through EOR mechanism analysis, CO₂ is the only fluid that is miscible with oil (even 90% mole fraction CO₂ is dissolved in the oil phase), which results in the lowest oil phase viscosity. The CO₂ diffusion mechanism is also pronounced in the huff-‘n-puff process. Water may impact on the oil recovery through gravity and the capillary force imbibition effect. N₂, cannot recover more crude oil only by elasticity and swelling effects. Secondly, the fracture arrangement in space has the most impact on CO₂ huff-‘n-puff, followed by water and finally N₂. The fractures primarily supply more efficient and convenient channels and contact relationships. The spatial arrangement of fractures mainly impacts the performance of CO₂ through viscosity reduction in the contact between CO₂ and crude oil. Similarly, the contact between water in fractures and crude oil in the matrix is also the key to imbibition. In the process of N₂ huff-‘n-puff, the elasticity energy is dominant and fracture arrangement in space hardly to improve oil recovery. In addition, when considering anisotropy, water huff-‘n-puff is more sensitive to it, while N₂ and CO₂ are not. Finally, comparing the relationship between fracture contact area and oil recovery, oil production is insensitive to contact area between fracture and matrix for water and N₂ cases.

Shale gas resources are highly abundant in the world. They can provide sustainable energy supply and have the potential to reduce energy prices. Therefore, shale gas has become one of the most important resources for oil and gas exploration and production, especially in North America today. Adsorption and desorption of methane gas are some of the important physical and chemical processes involved in the accumulation, transport, and production of shale gas. The shale matrix will shrink or swell due to the desorption or adsorption of methane gas, which will impact the recovery of shale gas reservoirs. The main purpose of this investigation is to quantitatively ascertain how the adsorption of methane gas affects the volumetric changes of the shale matrix. Based on the adsorption potential theory, a modified Dubinin–Astakhov (D–A) equation was employed to describe the adsorption of supercritical methane gas on shale. Then, a coupled adsorption–strain model was established to investigate the volumetric strain of shale induced by the combined effects of methane gas adsorption and stress compression. The methane adsorption and the induced shale swelling were measured on a black shale sample from the Sichuan Basin at 303.15 K and pressure up to 10 MPa, and the proposed models were employed to interpret the experimental data. The results demonstrate that the proposed models show good applicability and provide a reliable prediction. The swelling moduli of shale samples were obtained by fitting the experimental data using the coupled adsorption–strain model. The results indicate that the swelling modulus of shale in this study is generally greater than that of coal. The calculated ratios of Young’s modulus to the swelling modulus do not show great variation from shale to shale in this study, which is similar to coal. This study can be incorporated into the numerical simulation of the production process of shale gas reservoirs.

Based on the spontaneous imbibition phenomenon and seepage mechanism of the tight core, a spontaneous imbibition model of the tight reservoir was established. The imbibition experiment was used to verify the reliability of the model and reverse the parameters. The relative error between the experimental and model recovery is within 5%. The model is used to calculate the oil recovery and oil saturation distribution characteristics of spontaneous imbibition in tight reservoirs under different boundary conditions. The model results show that the imbibition area and imbibition recovery are different under different boundary conditions [one-end-open, two-end-open, two-end-close (TEC), and all-face-open (AFO)]. If the imbibition area increases, imbibition recovery increases. If the side is closed, the spontaneous imbibition occurring at two end faces does not interfere with each other in the initial stage. When the imbibition process under TEC conditions is advanced to the middle and late stage, the superimposed effect occurs between the two imbibition leading edges. Under the AFO condition, the imbibition process has a superimposed effect at the corner between the end face and the side face. The superimposed effect of the end face is more obvious than that of the side face. The superimposed effect not only improves the oil washing efficiency but also inhibits the imbibition area.

We used the nuclear magnetic resonance online detection method to analyze the water invasion mechanism and residual gas distribution of a carbonate rock gas reservoir. The T₂ spectra obtained by using the Carr‐Purcell‐Meiboom‐Gill (CPMG) pulse sequence were applied to characterize the invasion water and residual gas distribution. The results showed that (a) in the pore‐type gas reservoir, the water first invades the meso–macropores and then the small pores as the pressure decreases further. The fracture distribution in a fracture‐pore‐type gas reservoir has an effect on the water invasion mode. The water can enter the pores through the fracture wall after the water invades the fracture. (b) In the pore‐type gas reservoir, 37.7% of the residual gas resides in the small pores, while the rest resides in the macropores. While in the fracture‐pore‐type gas reservoir, 4.8% ~ 26.8% of the residual gas is in the smaller pores and 69.2% ~ 95.7% in the macropores. Barely, any residual gas resides in the fractures. The residual gas in the small pores is difficult to produce. (c) The residual gas is controlled by the fracture penetration, amount of bottom water, fracture width, and production rate. It is suggested the production rate decreased to induce the water to invade the meso–macropores after the gas well begins to produce water to reduce the amount of residual gas in the meso–macropores.