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

Abstract

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.

Laboratory Experiments of Hydrocarbon Gas Flooding and Its Influencing Factors on Oil Recovery in a Low Permeability Reservoir with Medium Viscous Oil

“…A smaller pressure gradient means that the driving force of hydrocarbon gas in the reservoir displacement is small, so the movement speed of gas will slow down, which makes the gas channeling time become longer . Finally, high back pressure will increase the gas displacement pressure difference, because high back pressure makes it easier for the liquid hydrocarbon molecules in the crude oil to remain stable, reducing the formation of bubbles in the liquid crude oil, which will reduce the relative fluidity of the crude oil, making it easier for the gas to push in the liquid crude oil, thus increasing the displacement pressure difference …”

“…30 Finally, high back pressure will increase the gas displacement pressure difference, because high back pressure makes it easier for the liquid hydrocarbon molecules in the crude oil to remain stable, reducing the formation of bubbles in the liquid crude oil, which will reduce the relative fluidity of the crude oil, making it easier for the gas to push in the liquid crude oil, thus increasing the displacement pressure difference. 31 4.3.3. Analysis of Influencing Factors the Gas Injection Rate.…”

Key Technologies of Numerical Simulation with CCUS and Application in a Low-Permeability Carbonate Reservoir of the Middle-East

“…The model assumes that the flow of oil-gas-water three-phase fluid obeys Darcy's law, the mass transfer and phase state change of each component and the phase equilibrium is completed instantaneously, the water component has independent phase state and does not participate in the interphase mass transfer of oil-gas, in that case of Nc virtual component, rock compressible and anisotropic, considering the influence of gravity and capillary force, and the oil-gas interface, Influence of tension on relative permeability, seepage process is isothermal flow, etc. [4][5][6][7] .…”

CO2-Low Interfacial Tension Viscoelastic Fluid Synergistic Flooding in Tight Reservoirs

“…The gas injection can replenish reservoir energy, reduce oil viscosity, expand crude oil, and improve oil mobility; this is the main choice for the development of tight reservoirs. CO 2 flooding is the most ideal way, which can realize underground storage to effectively reduce carbon emissions and has good economic and social benefits. − However, the existence of fractures and large pore channels easily leads to gas channeling during CO 2 injection, which limits the swept volume of CO 2 flooding and enhanced oil recovery (EOR) effect. , Hence, scholars have explored water alternating gas, foam, and gel technologies to regulate and control cracks, delay gas channeling, and improve the aspirating profile . The strong heterogeneity or high permeability grade difference in the tight oil reservoir more easily leads to ineffective water–gas alternating injection, and the remaining oil in the low permeability layer cannot be started .…”

“…13−18 However, the existence of fractures and large pore channels easily leads to gas channeling during CO 2 injection, which limits the swept volume of CO 2 flooding and enhanced oil recovery (EOR) effect. 19,20 Hence, scholars have explored water alternating gas, foam, and gel technologies to regulate and control cracks, delay gas channeling, and improve the aspirating profile. 21 The strong heterogeneity or high permeability grade difference in the tight oil reservoir more easily leads to ineffective water−gas alternating injection, and the remaining oil in the low permeability layer cannot be started.…”