Factors Affecting Water Alternating Hydrocarbon Gas Miscible Flooding in a Low Permeability Reservoir

Water alternating hydrocarbon gas miscible flooding integrates the improved microscopic displacement efficiency of gas flooding with the increased macroscopic sweeping volume of water injection and has been applied as an enhanced oil recovery method. The purpose of this research is to analyze effects of developmental factors on a water alternating hydrocarbon gas miscible flooding. A low permeability reservoir sector model with one producer and two injectors is conducted to determine the optimal dynamic parameters in water alternating hydrocarbon gas miscible flooding. Firstly, effects of three injection methods are analyzed. Then, factors of water alternating hydrocarbon gas miscible flooding discussed in this research include components of hydrocarbon gas, WAG ratios, and gas injection rates. Three injection methods, continuous water flooding, continuous hydrocarbon gas flooding and water alternating hydrocarbon gas miscible flooding, have an impact on the displacement efficiency and sweep efficiency, which effect the oil recovery. The mole percentage of C1 in injected gas is related to the minimum miscible pressure, which directly affects production performances of hydrocarbon gas miscible flooding. The value of this factor is scaled from 75% to 90% to discover its effect on oil recovery in this sector model. Different WAG ratios act differently in gas breakthrough and pressure maintenance. WAG ratios are respectively 1:5 (one month gas injection followed by five months water injection), 3:6 and 6:6 in this research. Gas injection rates are set from 5,000Mscfd to 15,000Mscfd to study their impacts on production performances. Results show that water alternating hydrocarbon gas miscible flooding gains higher displacement efficiency than continuous waterflooding and performs better in sweep efficiency than continuous hydrocarbon gas flooding. Under the similar condition, the mole percentage of C1 acts differently on reservoir performances. Along with the decrease of C1 mole percentage, oil recovery raises from 49.44% to 51.43%. Based on this, simulation schemes with different WAG ratios which impact the gas injection volume are carried out for further study. Compares to the results of 1:5 WAG ratio, and 3:6 WAG ratio, 6:6 WAG ratio contributes to a longer production plateau and a higher oil recovery accordingly. Furthermore, gas injection volume is related to the reservoir potential, and through observations, simulation scenario with 6:6 WAG ratio offers a sustainable higher production and shows higher potential in this research. When other factors stay unchanged, gas injection rate as the only variable raises from 5,000Mscfd to 15,000Mscfd, the oil recoveries of these simulation schemes increase. However, the increments of the oil recoveries gradually decline, which demonstrates that an appropriate injection gas rate can achieve a sufficient production performance and obtain a maximum economic benefit. Based on previous findings in this study, we can conclude that through studies of various factors that influence oil recovery, the results can be applied to determine an optimal strategy for the reservoir developed by hydrocarbon gas miscible flooding. In addition, it is also adapted to develop reservoirs by other WAG methods, such as carbon dioxide and non-hydrocarbons.