Effect of CO2 flooding in an oil reservoir with strong bottom-water drive in the Tahe Oilfield, Tarim Basin, Northwest China

The dissolution and diffusion of CO2 in oil and water and its displacement mechanism were investigated by laboratory experiment and numerical simulation for Block 9 in the Tahe oilfield, a sandstone oil reservoir with strong bottom-water drive in Tarim Basin, Northwest China. Such parameters were analyzed as solubility ratio of CO2 in oil, gas and water, interfacial tension, in-situ oil viscosity distribution, remaining oil saturation distribution, and oil compositions. The results show that CO2 flooding could control water coning and increase oil production. In the early stage of the injection process, CO2 expanded vertically due to gravity differentiation, and extended laterally under the action of strong bottom water in the intermediate and late stages. The CO2 got enriched and extended at the oil-water interface, forming a high interfacial tension zone, which inhibited the coning of bottom water to some extent. A miscible region with low interfacial tension formed at the gas injection front, which reduced the in-situ oil viscosity by about 50%. The numerical simulation results show that enhanced oil recovery (EOR) is estimated at 5.72% and the oil exchange ratio of CO2 is 0.17 t/t

Characteristics of water alternating CO2 injection in low-permeability beach-bar sand reservoirs

Water flooding can be ineffective in highly heterogeneous low-permeability beach-bar sand reservoirs. The introduction of CO2 flooding helps boost the oil production of the reservoirs but only in an early stage. During the late stage of flooding, gas channeling would occur. Water alternating gas (CO2) (WAG) process can be used to delay gas channeling and improve the effect of CO2 injection, though its adaptability to beach-bar sand reservoirs remains unclear. In order to clarify CO2 injection characteristics in these reservoirs, experiments were carried out in high-temperature high-pressure NMR on-line displacement experiment apparatus to simulate different flooding modes on synthetic cores that can reflect the vertical heterogeneity of beach-bar reservoirs. Different CO2 injection modes were implemented on these cores and the displacement characteristics and residual oil distribution features during both WAG injection and continuous CO2 injection were analyzed quantitatively and qualitatively. The results show that the scheme of WAG injection after continuous CO2 injection can obtain better oil displacement efficiency than that of the scheme of continuous CO2 injection after WAG injection, but there is no significant difference in respect of oil displacement efficiency of WAG flooding between the mode of bar-injection – beach-production (injection into bar sand – production from beach sand) and the mode of beach-injection – beach-production (injection into and production from beach sand), with the former mode having a higher oil recovery rate. The wider pore-size distribution range of microscopic residual oil after WAG injection shows great potential of enhancing oil recovery from subsequent continuous gas injection. When WAG injection is implemented prior to continuous CO2 injection, the displacement effect of the latter is more significant. This research may provide a theoretical basis for CO2 EOR in this type of reservoirs

A new model simulating the development of gas condensate reservoirs

A new simulation model for the development of gas condensate reservoirs is introduced based on the influence that phase change, non-Darcy flow, and capillary pressure have on the production of gas condensates. The model predicts well performance, including bottom-hole pressure, oil/gas production rate, oil/gas recovery, gas–oil ratio, and the change in produced fluid composition. It also calculates dynamic characters, such as the change of pressure field and oil/gas saturation field during the development of gas condensate reservoirs. The model is applicable to different boundary conditions (both constant-pressure and sealed boundary) and different production modes (both constant-pressure and constant-volume production modes). Model validation attempted using numerical simulation results for sealed boundary conditions with constant-pressure production mode has shown a relatively good match, proving its validity. For constant-pressure boundary conditions with constant-volume production mode, four stages are defined according to the dynamic behavior of production performance in the development of gas condensate reservoirs

Displacement characteristics of CO2 flooding in extra-high water-cut reservoirs

Carbon dioxide (CO2) flooding is a widely applied recovery method during the tertiary recovery of oil and gas. A high water saturation condition in reservoirs could induce a ‘water shielding’ phenomenon after the injection of CO2. This would prevent contact between the injected gas and the residual oil, restricting the development of the miscible zone. A micro-visual experiment of dead-end models, used to observe the effect of a film of water on the miscibility process, indicates that CO2 can penetrate the water film and come into contact with the residual oil, although the mixing is significantly delayed. However, the dissolution loss of CO2 at high water-cut conditions is not negligible. The oil-water partition coefficient, defined as the ratio of CO2 solubility in an oil-brine/two-phase system, keeps constant for specific reservoir conditions and changes little with an injection gas. The NMR device shows that when CO2 flooding follows water flooding, the residual oil decreases—not only in medium and large pores but also in small and micro pores. At levels of higher water saturation, CO2 displacement is characterized initially by a low oil production rate and high water-cut. After the CO2 breakthrough, the water-cut decreases sharply and the oil production rate increases gradually. The response time of CO2 flooding at high water-cut reservoirs is typically delayed and prolonged. These results were confirmed in a pilot test for CO2 flooding at the P1-1 well group of the Pucheng Oilfield. Observations from this pilot study also suggest that a larger injection gas pore volume available for CO2 injection is required to offset the dissolution loss in high water saturation conditions