Different from conventional oil and gas, the storage and seepage space of heavy oil reservoirs are extremely complicated, thereby making it difficult to describe reservoirs in detail over the heavy oil production process. Acquiring development results accurately in real time is still a demanding task, and it is also a challenge to predict the average remaining heavy oil saturation during the production process. Tracers are mostly used to monitor steam flooding to obtain the real-time dynamics during heavy oil production in fields. However, the flow pattern of gas tracers in heavy oil is still unclear, with very rare investigations. In this work, a new one-dimensional gas tracer convection–diffusion model that considered the retention and oil phase migration velocity was established using the percolation law of gas tracers. The reservoir description coefficient f was introduced to describe the relationship between the migration velocities of the oil and gas phases in the heavy oil reservoir. Subsequently, a new gas tracer well pattern flow model was also constructed based on the gas tracer linear flow model and verified simultaneously. The results revealed that at a larger partition coefficient, more amounts of gas tracers were distributed in the crude oil, the duration of stagnation was extended, and the start time of tracer production was moved backward. The injection velocity had a very minor effect on the tracer production performance. As the fluid injection rate increased, the duration of gas tracer production was extended; however, after the injection rate reached a certain level, the difference in the arrival time of the peak become minor. The effects of crude oil viscosity on the tracer production were reflected by the breakthrough time, production time, peak concentration, and peak arrival time of the tracer. Compared with the production curve of the crude oil viscosity, the peak of the production curve with high crude oil viscosity has a faster peak time and a large peak value. The reservoir description coefficient mainly affects the peak concentration of tracer production and has very minor effects on the production time and other parameters. The outcomes of this work can be applied in the field of heavy oil development, in particular, for the heavy oil reservoir description and dynamic monitoring.

Injection of imbibition fluids or CO2 during hydraulic fracturing is an effective stimulation method for tight oil reservoirs. Selecting appropriate agents is significant to optimize the integrated scheme of fracturing and production in tight oil reservoirs. In this study, a series of lab experiments, including spontaneous imbibition, dynamic imbibition, and huff and puff, were carried out using real tight cores, water absorption apparatus, and core flooding equipment. The EOR performances of imbibition fluids and CO2 in fractured tight cores were compared. The mass transfer of imbibition fluids and CO2 in tight oil reservoirs and its influence on the sweeping volume and EOR mechanisms were discussed. The results show that (1) the spontaneous imbibition rate of imbibition fluids in tight cores is slow, and the oil recovery factor by spontaneous imbibition in cracked cores is relatively high, up to 13.42%. (2) In the dynamic imbibition experiments, the final oil recovery by CO2 injection was significantly higher than that by injecting imbibition liquids. Because of the excellent miscibility effect of CO2, oil production by CO2 injection mainly occurred in the primary displacement stage. Comparatively, the EOR effect of imbibition fluids mainly played its role during production after well shut-in, which can increase the oil recovery factor by 7.35%-11.64%. (3) The influence of the huff and puff mode of CO2 on EOR performance is greater than that of imbibition fluids due to its more sensitive compressibility and mass transfer rate. Generally, a high oil recovery factor can be obtained if the depletion production is conducted first, and a huff and puff operation is followed. (4) Comprehensively understanding the mass transfer characteristics of CO2 and imbibition fluids in tight oil reservoirs can guide the fracturing parameter design, such as the order of fracturing fluid slugs, the optimal soak time, and fracture spacing.

Horizontal wells are commonly used in bottom water reservoirs, which can increase contact area between wellbores and reservoirs. There are many completion methods used to control cresting, among which variable density perforation is an effective one. It is difficult to evaluate well productivity and to analyze inflow profiles of horizontal wells with quantities of unevenly distributed perforations, which are characterized by different parameters. In this paper, fluid flow in each wellbore perforation, as well as the reservoir, was analyzed. A comprehensive model, coupling the fluid flow in the reservoir and the wellbore pressure drawdown, was developed based on potential functions and solved using the numerical discrete method. Then, a bottom water cresting model was established on the basis of the piston-like displacement principle. Finally, bottom water cresting parameters and factors influencing inflow profile were analyzed. A more systematic optimization method was proposed by introducing the concept of cumulative free-water production, which could maintain a balance (or then a balance is achieved) between stabilizing oil production and controlling bottom water cresting. Results show that the inflow profile is affected by the perforation distribution. Wells with denser perforation density at the toe end and thinner density at the heel end may obtain low production, but the water breakthrough time is delayed. Taking cumulative free-water production as a parameter to evaluate perforation strategies is advisable in bottom water reservoirs.

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