Experimental investigation of gas injection gravity drainage in naturally fractured reservoirs

摘要

Global energy consumption is increasing and hence the need for fossil fuels such as oil. Yet, conventional oil production from known reservoirs is about to reach its peak. So, more needs to be done to meet the demand in the near future. Enhanced oil recovery (EOR) among others is one of the ways to add to global oil production. Gas injection is considered one of the largely utilized EOR methods. Especially, gas supported gravity drainage process has great potential for production from dipping fractured reservoirs to assist the displacing fluid for producing more oil. This thesis presents an experimental investigation that evaluates the optimum performance of three-phase flow of gravity drainage under different miscibility conditions. In the experiments, glass bead models were used as the porous medium and analog fluids (a quaternary three-phase system of H2O, n-butyl alcohol “NBA”, hexadecane “C16¬” and NaCl) were used instead of actual water, oil and gas. An analogy between these fluids and reservoir fluids was constructed based on similar behaviours of the interfacial tensions of both systems. Simulated injection schemes include the continuous gas injection “CGI”, water alternating gas “WAG” and simultaneous water and gas injection “SWAG”. Various fracture patterns and injection rates were also used in the experiments in order to investigate their impacts. In addition, upward WAG injection under near-miscible condition in fractured glass beads model was investigated and its efficiency is compared to the downward near-miscible WAG flooding. The CGI scheme versus WAG and SWAG injection schemes under different conditions using the NBA-rich “oleic” phase indicates that CGI in the vertical injection gives a better performance than the WAG and SWAG injections. However, the CGI consumes more gas injection than the SWAG and WAG schemes, respectively. This implies that WAG injection seems to be more stable and feasible. For injection direction of displacing fluid, an upward injection has lower recovery and injection efficiency factors than downward injection of displacing fluid due to early gas breakthrough, which is related to the density difference between displacing and displaced fluids.The comparison between different miscibility experiments shows that the oil recovery is gradually increased under near-miscible and miscible conditions. The immiscible flood has a slightly sharp breakthrough compared to other two floods which leaves behind a higher residual oil. In addition, decreasing oil recovery and injection efficiency are noticed with reducing the miscibility between gas and oil-phase in the fracture model. This is believed to be a result of interfacial tension and capillary pressure effect, which could dominate the mass transfer between the matrix and fracture. In addition, the oil recovery in miscible flooding is lower than the near-miscible flooding since the gas phase is completely miscible and the oil phase which can pass easily through the fracture. Accordingly, the gas phase breakthrough occurs early in the miscible flooding. The comparison between intermediate and high flow rate of 1:1 WAG ratio and 0.2 PV slug size injections under immiscible condition in the conductive vertical fracture model is studied in this thesis. In contrast, intermediate flow of displacing fluid has a lower oil recovery than the high injection rate. This might have happened due to increasing possibility of mass transfer between the matrix and fracture. On the other hand, different injection rates (from the low to the high flow rate) under near-miscible condition in isolated vertical fracture model are investigated. Those lead to that the oil recovery slightly increases with reducing flow rate since the low injection rate has more stability of the diffusion and dispersion between the displacing and displaced fluids. Several fracture shapes (Isolated, double and conductive vertical fracture models) have been investigated. It is clearly shown that the conductive vertical fracture model has a lower oil recovery than other models and its gas breakthrough occurs early. The isolated vertical fracture model has a high oil recovery because it has two media, which are before and after the fracture. These sections can delay gas breakthrough and thereby increase oil production. Furthermore, the oil recovery factor is inversely proportional with the length of the fracture inside the model. The flow regions of all experiments are investigated using scaling laws reported by Zhou et al. (1994). The calculated scaling law numbers indicate that the optimum oil recovery and injection efficiency occur in the gravity-dominated region, which is represented by the low injection rate and near-miscible fluids.