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Determination of CO2 volume injection effect to reservoir fluid characteristic in miscible CO2 displacement

Carbon dioxide (CO2) miscible flooding is one of the Enhanced Oil Recovery (EOR) methods that has been recognized as a promising method to improve of oil recovery before abandonment. In addition, many issues related to global warming or greenhouse effect due to CO2. By using CO2 as either miscible or immiscible flooding to enhance oil recovery injected into reservoir, it may help reduce environmental problems. Carbon dioxide (CO2) is able to improve of oil recovery effectively by important key parameter: minimum miscibility pressure (MMP), viscosity, and density. This paper aims to determine the effect of CO2 volume injection to reservoir fluid characteristic in order to CO2 miscible flooding for displacing the oil production. This research was carried out by some series of laboratory experiment that involve PVT test, slim tube test, and swelling test. The result from laboratory experiments were used to observe the use of CO2 and its effect on reservoir fluid characteristics such as viscosity, solubility, and swelling factor. MMP obtained from slim tube test is 2805 Psi. Based on the results, all trend of parameters: viscosity, solubility, and swelling factor showed the positive impact of CO2 have on liquid recovery.


Introduction
Most of the production of the oil fields in Indonesia have been declined and currently been recovered mostly by primary and secondary methods. Yet, there a large amount of remaining oil in the reservoir and require to be produced using Enhanced Oil Recovery (EOR) methods to improve of oil recovery before abandonment. One of the Enhanced Oil Recovery (EOR) methods that has been successfully improved oil recovery is the Carbon dioxide (CO2) miscible flooding [1]. CO2 flooding is also one of the most promising techniques to improve oil recovery for light and heavy oil as well [2]. In addition, many issues related to global warming or greenhouse effect due to CO2 [3]. By using CO2 as either miscible or immiscible flooding to enhance oil recovery injected into reservoir, it may help reduce environmental problems [4]. Carbon dioxide (CO2) is able to improve oil recovery effectively by important key parameter: minimum miscibility pressure (MMP), viscosity, and density [5]. Minimum miscibility pressure (MMP) can be defined as the lowest pressure at which (90-92%) of oil has been recovered at (1.2 pore volume) of CO2 injected [6] MMP is depends on composition of reservoir fluid and injection gas compositions, reservoir pressure, and temperature [7]. The greatest difference compared to other gases is that CO2 can extract heavier components up to C30 and the solubility of CO2 Understanding of CO2 -fluid reservoir physical properties and its characteristic also its effect for displacing the oil is very important in miscible gas flooding [9]. The important parameters that were influenced on gas flooding EOR are solubility, swelling factor, viscosity, and density between gas injection and fluid reservoir [10]. This study was aimed to shows the effect of CO2 miscible flooding for oil fields by swelling, reducing viscosity, and solubility which affecting on oil recovery that contributing to the oil production.

Method and data
This research was carried out by some series of laboratory experiment that involve PVT test to determine fluid composition, slim tube test to determine minimum miscibility pressure (MMP), and swelling test to determine swelling factor of miscible CO2 and reservoir fluid. All these tests are performed with sample from one of oil field in Indonesia. In addition, original fluid reservoir and separator condition for sampling PVT is shown in table 1. PVT test are designed to study and quantify the phase behavior and properties of a reservoir fluid [11]. Basically, the sampling of reservoir fluid for PVT test was carried out at the surface or separator and frequently collected at separator which are then recombined to obtain a well stream fluid for full PVT analysis [12]. During the PVT test process, the bubble point pressure (Pb), oil formation volume factor (Bo), and gas to oil ratio (GOR) were measured [13]. The result of oil composition can be shown in table 2.
The slim tube test was carried out to determine the minimum miscible pressure (MMP). In addition, the prediction of MMP can be obtained from the intersection of the trend lines on oil recovery with the injection pressure [14]. The slim tube test was carried out after constant mass depletion test, where bubble point pressure of the reservoir oil was measured, because this experiment was repeated several times at different pressure above bubble point pressure [15]. MMP for this experiment yielding 2805 Psi (can be seen in Figure 1). After minimum miscible pressure (MMP) was measured by slim tube test, the measurement of oil swelling (mixture of CO2 and fluid reservoir) can be done. So, swelling test was the final step of laboratory experiment after PVT and Slim tube test was done. The viscosity, density, and flash test of the CO2 and fluid reservoir mixture (swelling oil) were measured at saturation pressure were measured prior to injection and at various carbon dioxide (CO2) injection percentage.
The fluid sample was separated to a flash separation at standard conditions (P = 14.73 psia and T = 60 o F) to obtain original hydrocarbon gas and carbon dioxide (CO2) injected. By using flashed data, the solubility of gas and fluid reservoir after injecting CO2 and swelling factor (SF) at bubble-point pressure can be obtained.

Result and discussion
The result of CO2 and fluid reservoir properties interaction in reservoir are key parameter to know the effect on oil recovery that is needed for carbon dioxide (CO2) gas flooding enhanced oil recovery. The sample was taken from one of oil field in Indonesia. Oil sample was tested with variation of carbon dioxide (CO2) gradually different percentage. Minimum miscible pressure (MMP) obtained from slim tube test of CO2 -fluid is 2805 Psi as shown in figure 1. The result obtained from laboratory experiment are CO2 injected stream percentage, the mixture of CO2 -bubble point pressure, the mixture of CO2 injection and fluid density, the mixture of CO2 injection and oil viscosity, the swelling factor of CO2 addition and oil, and the solubility of CO2 and oil. Overall, the effect of CO2 injection to fluid reservoir characteristic can be seen from phase diagram (figure 2) of fluid reservoir composition after injecting of CO2 [16]. Figure 2 shows phase diagram of original reservoir fluid and reservoir fluid after injecting CO2. The black line is the original reservoir fluid hydrocarbon composition prior to CO2 flooding and the red line is phase diagram of the change reservoir fluid by CO 2 injection into reservoir. Miscible CO 2 flooding into reservoir causes phase envelope shifting, then increase critical point of reservoir fluid so that saturation pressure or bubble point pressure increase as well. Phase diagram also indicate that the dew point drops, the bubble point decreases, and the two-phase envelope diagram shrinks with the increase of CO2 composition [17]. All these trends showed the positive impact of CO2 have on liquid recovery [18]. Figure 3 illustrates the results of the CO2 -oil reservoir mixture by CO2 addition at minimum miscibility pressure (MMP) and reservoir temperature. Swelling is defined as the increasing in bubble or saturated liquid phase volume compared to the initial reference volume at reservoir temperature [19]. The swelling factor can be obtained by using flashed data from swelling test. Figure 3 shows that as more CO2 dissolve into the liquid phase, as the volume of the liquid phase and bubble pressure increase, as a result of the oil swelling is increased, so swelling factor increased as well.

The solubility of the CO2 and oil mixture
The effect of CO2 addition by injecting into reservoir to the solubility of CO2 and oil mixture can be seen in figure 4. The solubility of CO2 and oil mixture is increased by the increasing of CO2 percentage at MMP. The higher dissolved gas content increases the driving force naturally to produce oil in the reservoir.    Figure 5 illustrates the results of the CO2 and oil viscosity with variation of bubble point pressure at reservoir temperature. Each line in this figure represents the mixture of CO2 -oil viscosity with different saturation pressure (bubble point pressure) from minimum miscibility pressure (MMP) till above MMP. This figure can also be observed that the mixture of CO2 -oil reservoir was significantly reduced by carbon dioxide (CO2) injection. The reduction of oil viscosity improved the total mobility ratio between reservoir oil and the displacing fluid, which will affect the recovery factor [20].

Conclusion and recommendation
Throughout this research, the following conclusions and recommendations can be concluded based on the discussion and results:  CO2 flooding is one of the promising enhanced oil recovery method that require to gas and oil properties for oil displacement process.  CO2 addition into reservoir by injecting at minimum miscible pressure (MMP) give the leverage on the changes of reservoir fluid characteristic, such as viscosity, swelling factor, solubility, even the composition of hydrocarbon which can be seen from the mixture of CO 2 and oil phase behaviour.  The increasing of CO2 volume injection percentage at minimum miscible pressure lead to decreasing of viscosity whereas the reduction of viscosity improved the total mobility ratio between reservoir oil and the displacing fluid, which will affect the recovery factor.  By increasing of CO2 volume injection at minimum miscible pressure lead to increasing of the solubility and swelling factor as well.