© V. Rahimi et al., published by IFP Energies nouvelles, 2017

Introduction

In recent decades, the high price of oil and the growing demands of oil have led to the development of various Enhanced Oil Recovery (EOR) methods. CO₂ is used extensively in EOR techniques due to its low injectivity problems, low formation volume factor, low Minimum Miscibility Pressure (MMP), abundance of reserves, and high incremental oil recovery compared to other gases (Majidaie et al., 2013). Theoretical investigations on the application of CO₂ for EOR started in the early 20th century (Rogers and Grigg, 2000). Over the past few decades, extensive laboratory studies, numerical simulations, and field applications of CO₂-EOR processes have been reported (Burke et al., 1990; Grigg and Schecter, 1993; Idem and Ibrahim, 2002; Moritis, 2006; Chukwudeme and Hamouda, 2009; Hamouda et al., 2009; Manrique et al., 2010; Enick and Olsen, 2012). Several CO₂-EOR methods have been suggested and developed, such as continuous CO₂ flooding and Water-Alternating-CO₂ (CO₂-WAG) flooding under immiscible and miscible displacements. Continuous CO₂ flooding is considered as one of the largest utilized EOR methods which is proven as a highly effective EOR method in the petroleum industry (Alquriaishi and Shokir, 2011). The main displacement mechanisms for improved oil recovery during the CO₂-EOR include CO₂-oil Interfacial Tension (IFT) reduction, oil swelling, oil viscosity reduction, solution gas drive, and extraction of light and intermediate hydrocarbons for immiscible CO₂ flooding to completely miscible displacement (Blunt et al., 1993; Tunio et al., 2011; Cao and Gu, 2013; Song et al., 2014). In miscible displacement, CO₂ is fully mixed with the reservoir oil causing oil swelling and viscosity reduction. This reduction of the viscosity in heavy oil is higher compared to light oil (Baviere, 1991; Agbalaka et al., 2008; Sohrabi et al., 2008). Despite these advantages, continuous CO₂ flooding has some limitations both technically and economically. Technically, since CO₂ is injected under supercritical conditions, its viscosity is less than most types of crude oils, which can lead to viscous fingering, gravity override, and the formation of preferential paths in the reservoir rock (Bednarz and Stopa, 2014). This problem causes an early CO₂ Breakthrough (BT) and a reduction of volumetric sweep efficiency. Economically, a large amount of CO₂ is needed in continuous CO₂ flooding. Relatively high operating costs of CO₂ transportation, storage, and compression may seriously limit many field applications of continuous CO₂ flooding (Holt et al., 2009).

To improve the volumetric sweep efficiency and reduce the amount of CO₂ needed for continuous CO₂ flooding, CO₂ is typically injected into the reservoir alternately with water. This process is called CO₂-WAG flooding. The first field application of WAG flooding was done in the North Pembina oil field in Alberta, Canada, by Mobil in 1957 (Christensen et al., 2001; Mirkalaei et al., 2011). The CO₂-WAG flooding is the combination of the improved volumetric sweep efficiency of water flooding with the enhanced microscopic displacement efficiency of CO₂ flooding, which can lead to a better displacement and an increase of oil recovery compared to continuous CO₂ flooding or water flooding (Christensen et al., 1998, 2001; Sohrabi et al., 2004; Kulkarni and Rao, 2005; Dehghan et al., 2009; Rouzbeh and Larry, 2010). On the other hand, in the CO₂-WAG flooding, the injected CO₂ reduces the oil viscosity while water sweeps the mobilized oil to the production well (Ghedan, 2009). Apart from the technical advantages mentioned, economically, the CO₂-WAG flooding can considerably reduce CO₂ consumption in comparison with continuous CO₂ flooding. In a review of 59 WAG flooding field applications by Christensen et al. (2001), which 24 of those projects were miscible CO₂-WAG flooding, it has been reported that most CO₂-WAG flooding projects result in an increase of average oil recovery of 5–10% Original Oil in Place (OOIP) (Christensen et al., 2001; Skauge and Stensen, 2003).

The main factors influencing the WAG flooding include reservoir wettability, reservoir heterogeneity, reservoir rock and fluid properties, injection techniques, and WAG parameters (slug size and WAG ratio) (Righi and Pascual, 2007). Two of the most important economic parameters affecting the WAG flooding are slug size and WAG ratio. The slug size refers to the volume of the injected CO₂ in each WAG cycle. The slug volume is usually expressed as a percentage of rock Pore Volume (PV) (Farouq, 2003). The optimum CO₂ slug size is critical in a proper design of miscible WAG flooding (Gale, 2003). The optimum CO₂ slug size for a particular project depends on economical factors such as crude price, CO₂ cost, and the amount and timing of the incremental recovery. The ultimate CO₂ slug size can be determined after the start of project, when more information is known about future price of oil and production response of the reservoir. The WAG ratio is very important in CO₂-WAG flooding design (Chen et al., 2010; Farshid et al., 2010). An optimum WAG ratio has a significant effect on operations and economics of a CO₂ flooding. The WAG ratio is defined as the ratio of the injected water volume to CO₂ volume in each WAG cycle (Farouq, 2003). To maximize the net present value of CO₂ flooding, the WAG ratio should be increased gradually after achieving optimum CO₂ production (Christensen et al., 1998). The gradual increase of the injected water results in increased mobility control and a constant produced CO₂ profile. If the WAG ratio is low, the injected excessive CO₂ will flow much faster than the injected water, which leads to an early CO₂ BT and a low volumetric sweep efficiency (Rao and Girard, 2002). Therefore, it is required to determine the optimum WAG ratio for WAG flooding process.

Although numerous experimental studies and numerical simulations have been performed in the past to investigate the CO₂-WAG flooding processes in various oil reservoirs, so far fewer studies have been done on the miscible CO₂-WAG flooding processes through the real reservoir core samples in heavy oil formations. The Sarvak formation has a heavy oil with American Petroleum Institute (API) gravity of 18.81° and approximately 30 billion barrels of the OOIP, which is located in south-western Iran. In this research, a number of sandstone core samples were taken from the Sarvak formation in Iran. Several slim-tube experiments were done at different displacement pressures and the constant reservoir temperature. Then, the MMP between the Sarvak heavy oil and CO₂ was determined by plotting the oil RF versus displacement pressure. A total of seven core flooding experiments were conducted to measure the oil RF and oil production of different CO₂-EOR methods. The following CO₂-EOR processes were examined and compared: three different flooding methods of water flooding, miscible continuous CO₂ flooding, and miscible CO₂-WAG flooding; three different WAG slug sizes of 0.15, 0.25, and 0.50 PV; three different WAG ratios of 1:1, 2:1, and 1:2. In general, the main objective of this work is the performance evaluation of the miscible CO₂-WAG flooding process as a function of slug size and WAG ratio based on ultimate oil recovery in the Sarvak formation.

1 Experimental Details

1.1 Materials

In this study, the oil sample and reservoir brine were collected from the Sarvak formation of Azadegan oilfield in Ahvaz, Iran. The oil sample is heavy gravity (18.81 API). The physical properties and detailed analysis of Stock Tank (dead) oil sample are listed in Table 1. Also, the compositional analysis of dead oil sample used in all experiments is shown in Figure 1. As can be seen, the total molar percentages of C_1-11 and C₁₂₊ are equal to 37.65 and 62.35 mol%, respectively. These data show that the oil sample contains a large amount of heavy components. The composition of reservoir brine, which PH at the ambient temperature is equal to 6.5, is given in Table 2. However, a synthetic brine was prepared for the core flooding experiments. The synthetic brine contained 290000 mg/L (ppm) NaCl, which was equal to the Total Dissolved Solids (TDS) of the reservoir brine.

CO₂ with a purity of 99.998 mol% was used in this study as the injecting gas. The density and viscosity of CO₂ at the reservoir pressure of 26.20 MPa and T_res = 96.1 °C were equal to 0.596 g/cc and 0.0487 cp, respectively. These data were calculated by using the PVTi module of ECLIPSE Simulation Software with 3-Parameter Peng-Robinson equation of state.

A number of sandstone core samples were taken from the Sarvak formation of Azadegan oilfield in the same region where oil and brine samples were collected. The diameter of these samples was equal to 3.8 cm. Also, the length, porosity, and permeability of the collected core samples were in the range of 15.50–19.50 cm, 15.46–19.05%, and 23.40–46.61 md, respectively.

Figure 1 Compositional analysis results of dead oil sample.

1.2 Miscibility (Slim-Tube) Apparatus

The first slim-tube experiment has been done in the early 1950s. The slim-tube apparatus is widely considered as a standard method in the industry for estimating MMP. Figure 2 shows a schematic diagram of the slim-tube apparatus. The slim-tube apparatus has three main sections: slim-tube coil; upstream and downstream sections.

The slim-tube coil (porous media) has a narrow and long stainless-steel coiled tubing with an inner diameter of 0.635 cm and a length of 1200 cm (to a one-dimensional displacement and minimize the viscous fingering and gravity segregation). The tube was packed with glass beads of 100 mesh size to create a porous media. The porosity and permeability of porous media were equal to 35% and 3000 md, respectively. The permeability of porous media is high and the pressure drop across the slim-tube coil was minimized. The slim-tube coil was placed in an air bath to maintain the reservoir temperature.

The upstream section consists of three piston accumulators (oil, CO₂, and toluene) and a high pressure pump. The CO₂ accumulator was placed inside the air bath to create the reservoir temperature conditions for CO₂. The accumulators were connected to the high pressure pump to move the fluids into the slim-tube coil.

The downstream section consists of a sight glass and a Back-Pressure Regulator (BPR). The sight glass was generally applied to visual inspection of the produced fluids and help in determination of miscibility conditions. The BPR was placed in the air bath and was used to maintain the pressure inside the slim-tube coil. Finally, in the outlet of slim-tube apparatus, the produced fluids were separated and collected after the BPR at the atmospheric pressure. It should be noted that the pressure drop across the slim-tube coil was measured using a pressure transducer.

Figure 2 Schematic diagram of slim-tube apparatus.

1.3 Core Flooding Apparatus

The core flooding apparatus is designed to carry out the core flooding experiments at high pressure and temperature. A schematic diagram of the core flooding apparatus used in this study is shown in Figure 3. The apparatus consists of four main sub-systems: injection system; displacement system; production system; and temperature control system.

In the fluid injection system, a High Performance Liquid Chromatography (HPLC) pump was used to inject the fluids stored in transfer cylinders (oil, CO₂, and brine) into the core samples at a constant rate. The distilled water was transported from the HPLC pump to the bottom of floating piston transfer cylinders to move the piston upward and compact the desired fluids.

The fluids displacement under actual reservoir conditions occurred inside the core samples placed in the core holder. The high pressure nitrogen was pumped by using a high pressure syringe pump to supply overburden pressure to the core holder, which is usually between 3.0–5.0 MPa higher than the injection pressure. The pressure transducer was used to measure the pressure drop across the core samples.

In the production system, a BPR was used to produce a constant production pressure during the core flooding experiments. Finally, the produced fluids (oil, CO₂, and brine) were collected and separated in a separator. The CO₂ production was measured by using a gas flow meter.

The fluids transfer cylinders, core holder, BPR, and flow lines were placed inside an air bath. A heater and a temperature controller were used to heat the air bath and maintain the constant reservoir temperature of 96.1 °C.

Figure 3 Schematic diagram of core flooding apparatus.

2 Experimental Procedure

In this section, the MMP determination procedure by slim-tube apparatus and the core flooding experiments are described in detail. In all experiments, the supercritical CO₂ and synthetic brine were injected to displace dead oil.

2.1 Slim-Tube Experiments

The slim-tube displacement experiments were run to determine the MMP needed to establish dynamic miscibility of the Sarvak heavy oil sample with CO₂ at the reservoir temperature. To do the slim-tube experiments, the porous media in the tube was first saturated with the Sarvak oil sample. The coiled tube was maintained at the reservoir temperature and a pressure above the bubble point pressure (P_b = 9.87 MPa) by using the air bath and BPR, respectively. Then, to displace oil, CO₂ was injected into the tube at a constant rate of 0.2 cc/min. Generally, the pressure drop across the coiled tube is very small, so, the entire displacement pressure is considered to be constant. The experiments were completed when 1.2 PV of CO₂ was injected. The slim-tube experiments were done at several different pressures at the reservoir temperature. In each experiment, the oil RF after 1.2 PV of CO₂ injected was recorded. By plotting the oil RF at each displacement pressure versus pressure, the MMP value was obtained. The most common criterion for the MMP determination was used, namely the curve break-over point in this plot (Ahmadi, 2011). It should be noted that before and after each experiment run, the slim-tube coil was cleaned with toluene.

2.2 Core Flooding Experiments

Seven experiments were run on the 7 core samples taken from the Sarvak formation with various properties to investigate the performance of the miscible CO₂-WAG flooding process. These experiments were examined in the form of three scenarios. In the first scenario, the different flooding methods like water flooding, miscible continuous CO₂ flooding, and miscible CO₂-WAG flooding were compared to investigate the effect of each of them on the oil RF and select the optimum method. In the second and third scenarios, a series of miscible CO₂-WAG floodings were performed and the optimum slug size and WAG ratio were determined.

Before the core flooding experiments, the sandstone core samples were cleaned with toluene, methanol, and chloroform to remove hydrocarbons, salts, and clays, respectively and dried. After preparing the core samples, they were placed horizontally inside the core holder and evacuated by using a vacuum pump. Then, the core samples were saturated using the synthetic brine to measure the porosities. By weighing the dried and wetted core samples and using the density of the synthetic brine, the PV was calculated (Eq. 1). Therefore, by knowing the Bulk Volume (BV), the porosity of the core samples was determined using Equation (2). (1) (2)

After porosity determination, the absolute permeability of the core samples was measured by injecting the synthetic brine at different flow rates and the corresponding pressure drops measurement. At first, the synthetic brine was injected with a low flow rate to reach the steady state flow conditions. The Darcy's law was applied to calculate t absolute permeability which can be rearranged as follows: (3) where q is the flow rate, μ is the viscosity of the synthetic brine, A is the cross-sectional area of the core samples, k is the absolute permeability of the core samples, ΔP is the pressure drop across the core samples, and L is the length of the core samples. By plotting qμ/A versus ΔP/L and using the linear regression, the absolute permeability of the core samples was calculated which is equivalent to the slope of the straight line fitted to the data.

After measuring the absolute permeability, the Sarvak heavy oil was injected into the core samples saturated with the synthetic brine at a constant rate of 0.2 cc/min in order to achieve the connate water saturation. By knowing the initial volume of the synthetic brine inside the core samples and the volume of the effluent brine, the connate water saturation was calculated. Also, the initial oil saturation was obtained by knowing the volume of the oil injected and the PV of the core samples. The measured porosity, absolute permeability, connate water saturation, and initial oil saturation of core samples used in this study have been shown in Table 3.

In order to carry out the flooding experiments at the reservoir conditions, after preparing the core samples and reaching the connate water saturation and the initial oil saturation, a heater and a temperature controller were used to increase the air bath temperature from ambient to 96.1 °C (reservoir temperature) and maintain this temperature.

In the water flooding experiment (experiment 1), after the core sample was pressurized to 26.20 MPa, the synthetic brine was injected at a constant injection rate of 0.2 cc/min and T_res = 96.1 °C. The brine flooding was continued until no more oil was produced (1.5 PV of the synthetic brine was injected).

In the miscible continuous CO₂ flooding experiment (experiment 2), the supercritical CO₂ was injected at a constant injection rate of 0.2 cc/min and T_res = 96.1 °C. The production pressure was set to be 26.20 MPa which is higher than the MMP of CO₂. The CO₂ flooding was continued until no more oil was produced (2.25 PV of CO₂ was injected).

In the miscible CO₂-WAG flooding experiments (experiments 3–7), the supercritical CO₂ and synthetic brine were injected into the core samples alternately at the same constant injection rate of 0.2 cc/min, the production pressure of 26.20 MPa, and T_res = 96.1 °C with the different slug sizes of 0.15, 0.25, and 0.50 PV (experiments 3–5) and the different WAG ratios of 1:1, 2:1, and 1:2 (experiments 3, 6, and 7). The CO₂ and brine flooding alternately in each miscible CO₂-WAG flooding experiment was continued until no more oil was produced.

It should be noted that, in all of miscible CO₂-WAG flooding experiments, the first fluid injected was CO₂.

3 Results and Discussion

3.1 Determination of MMP

The MMP is considered as one of the most important parameters in the design of miscible CO₂-EOR projects and criterion of miscibility. To determine the MMP value in this study, six slim-tube experiments were conducted at six different displacement pressures of P between 15.71 and 40.53 MPa and the constant reservoir temperature of 96.1 °C. These pressures were chosen carefully to cover the whole range of an immiscible state to a miscible state. In each pressure, the oil RF after injecting 1.2 PV of CO₂ was recorded and plotted versus displacement pressure (Fig. 4). As can be seen, at the pressures less than the MMP, the oil recovery increment is considerable by increasing the pressure but at the pressures higher than the MMP, this oil recovery increment is not significant. Based on the measured data in Figure 4, the oil RF was correlated to the displacement pressure by applying the two linear regressions: (4) (5)

By equalization the above two equations, the pressure was calculated at the point of intersection of the two linear regressions (break-over point) which this pressure is the same MMP. Therefore, the MMP between CO₂ and the Sarvak heavy oil was determined to be 25.92 MPa at T_res = 96.1 °C by using the slim-tube apparatus.

Figure 4 Oil RF versus displacement pressure in slim-tube experiment.

4 Comparison of Different Flooding Methods

In this research, three different flooding methods of water flooding, miscible continuous CO₂ flooding, and miscible CO₂-WAG flooding were applied to investigate the effect of each of them on the oil RF in the Sarvak formation and select the optimum method with respect to ultimate oil recovery. These experiments involve flooding CO₂ and the synthetic brine continuously and alternately into the oil saturated core samples to reach the ultimate oil RF. In the miscible CO₂-WAG flooding, a total of seven WAG cycles were done with the slug size of 0.15 PV and the WAG ratio of 1:1.

The measured oil RF and oil productions of the water flooding (experiment 1) and the miscible continuous CO₂ flooding (experiment 2) have been shown in Figure 5. As can be seen from this figure, the miscible continuous CO₂ flooding has a higher oil production rate and oil RF than the water flooding, which it is due to a zero CO₂-oil IFT, reduction of oil viscosity and oil swelling. According to Figure 5, water BT occurred at 0.56 PV (the oil RF was 33.1%) in experiment 1. Before water BT, the oil recovery was increased quickly. Nevertheless, only a very small amount of the residual oil (4.6%) was recovered after water BT. This is because the water saturation was increased quickly after water BT and the water channels were established between the inlet and the outlet of the core holder. In contrast to water flooding, the miscible continuous CO₂ flooding in experiment 2 had a different oil production trend after CO₂ BT. As shown in Figure 5, CO₂ BT happened at 0.21 PV (the oil RF was 25.3%). After CO₂ BT, a significant amount of the residual oil (36.2%) was produced. In the miscible continuous CO₂ flooding from 0.95 to 1.25 PV, the oil RF did not increase at all. This is because in the miscible continuous CO₂ flooding from 0.95 to 1.25 PV, a very large amount of CO₂ moved ahead of oil which caused some oil trapping. This factor led to a jump in oil RF of the miscible continuous CO₂ flooding after 1.25 PV.

The measured oil RF and oil productions of the miscible CO₂-WAG flooding (experiment 3) are plotted in Figure 6. As seen in this figure, CO₂ BT occurred at 0.31 PV in the second WAG cycle, which was delayed compared to 0.21 PV in the miscible continuous CO₂ flooding. A very large amount of the residual oil (69.9%) was produced after CO₂ BT (25.9%, 16.3%, 18.3%, and 9.4% of the residual oil were recovered in the second, third, fourth, and fifth WAG cycles, respectively, but no more oil was recovered in the sixth and seventh WAG cycles). According to Figure 6, water BT happened at 0.73 PV in the third WAG cycle, which was delayed in comparison with 0.56 PV in the water flooding. The oil RF and oil production rate before water BT is higher than after water BT. This is because the water saturation was gradually increased after water BT and the water channels were gradually formed as far as the water production was increased quickly in the last two WAG cycles. As a result, no more oil was recovered in the last two WAG cycles. As can be seen from Figure 6, the oil RF did not increase at all in a short distance from 0.31 to 0.36 PV. This is because CO₂ BT occurred at 0.31 PV.

The measured oil RF of three different flooding methods are shown in Figure 7. The ultimate oil RF of the miscible CO₂-WAG flooding was the highest (84.3%) at a total of 2.1 PV of injected CO₂ and brine in comparison with the miscible continuous CO₂ flooding (61.5%) at a total of 2.25 PV of injected CO₂ and the water flooding (37.7%) at a total of 1.5 PV of injected brine. In the miscible continuous CO₂ flooding, a lower viscosity of the injected CO₂ than the residual oil causes increasing the mobility ratio and the resulting viscous fingering and channeling. Also, the gravity overriding occurs due to a high density difference of the injected CO₂ and the residual oil. These results lead to a low volumetric sweep efficiency. In the miscible CO₂-WAG flooding, the injected water controls the mobility and stability of CO₂ displacement front, which causes delaying the gravity overriding and viscous fingering and the resulting a high volumetric sweep efficiency. At the same time, the injected CO₂ under the miscible conditions improves the microscopic displacement efficiency far better than the injected water. Therefore, the miscible CO₂-WAG flooding has a lower residual oil trapped in the Sarvak formation and increases the ultimate oil RF compared to the miscible continuous CO₂ flooding and water flooding.

Figure 5 Comparison of oil RF and oil production for water flooding and miscible continuous CO2 flooding.

Figure 6 Oil RF and oil production of miscible CO2-WAG flooding.

Figure 7 Comparison of oil RF for water flooding, miscible continuous CO2 flooding, and miscible CO2-WAG flooding.

4.1 The Effect of Slug Size in the Miscible CO₂-WAG Flooding

In this study, to investigate the effect of slug size on the oil RF of the miscible CO₂-WAG flooding, three experiments were performed with different slug sizes of 0.15, 0.25, and 0.50 PV at the WAG ratio of 1:1 (experiments 3–5). In experiments 4 and 5, a total of 2.0 PV of CO₂ and the synthetic brine were injected into the core samples in four and two cycles, respectively. In general, the slug size refers to the volume of the first fluid (CO₂) injected in each cycle and is expressed as a percentage of PV.

The measured oil RF of the three miscible CO₂-WAG flooding experiments are plotted and compared in Figure 8. As shown in this figure, a large amount of the residual oil was recovered in these three experiments before water BT. But after water BT, the oil recovery is lower (water BT of experiments 3–5 occurred at 0.73, 0.75, and 0.83 PV, respectively). The increase of injected water volume in porous media during the miscible CO₂-WAG flooding can cause a waterblocking phenomenon and prevent the injected CO₂ from being contacted with a large amount of the residual oil. This phenomenon, which was found in the water-wet oil reservoir (Huang and Holm, 1988), leads to a severe reduction of the oil RF and oil production rate. Therefore, the miscible CO₂-WAG flooding should be designed so that it does not prevent the injected CO₂ from being contacted with a large amount of the residual oil and does not occur the waterblocking effect.

Figure 8 also shows that the ultimate oil RF of experiment 3 with the slug size of 0.15 PV is the highest (84.3%) in comparison with experiments 4 (82.9%) and 5 (78.6%). This is because experiment 3 has the lowest slug size and its waterblocking effect occurred later than experiments 4 and 5, which the resulting more CO₂ contacted with the residual oil. Hence, the slug size has strong effect on the oil RF of miscible CO₂-WAG flooding. When a large amount of CO₂ contacts with oil under the miscible conditions, a strong mass transfer occurs between CO₂ and oil. As a result, more CO₂ is dissolved inside the oil, which causes a further reduction of oil viscosity and its swell.

Therefore, from the comparison of three miscible CO₂-WAG flooding experiments with the slug sizes of 0.15, 0.25, and 0.50 PV, it can be concluded that experiment 3 with the slug size of 0.15 PV is the most efficient with respect to the ultimate oil RF. Nevertheless, using a smaller slug size increases the operating cost due to a more frequently switch of the fluid injection. Hence, an optimum slug size should be determined for field applications of miscible CO₂-WAG flooding.

Figure 8 Comparison of oil RF for WAG slug sizes of 0.15, 0.25, and 0.50 PV.

4.2 The Effect of WAG Ratio in the Miscible CO₂-WAG Flooding

In this work, to study the effect of WAG ratio on the oil RF of the miscible CO₂-WAG flooding, three experiments were carried out with different WAG ratios of 1:1, 2:1, and 1:2 at the slug size of 0.15 PV (experiments 3,6, and 7). In experiments 6 and 7, a total of 2.25 PV of CO₂ and the synthetic brine were injected into the core samples in five cycles. In general, the WAG ratio is defined as the ratio of the injected brine volume to CO₂ volume in each cycle.

Figure 9 shows the measured oil RF of three experiments 3, 6, and 7. As can be seen, generally, experiment 6 has a higher oil production rate (the slope of the oil RF versus PV injected curve) during the experiment in comparison with experiments 3 and 7. Also, this figure shows that the ultimate oil RF of experiment 6 is the highest (93.4%), which was followed by experiment 3 (84.3%) and experiment 7 (83.7%). Under the miscible conditions, CO₂ has a much higher microscopic displacement efficiency compared to water. At a high WAG ratio, the injected water controls the CO₂ mobility pretty well and a large amount of CO₂ contact with the residual oil, which will lead to a high microscopic displacement efficiency and a great reduction of oil viscosity. On the other hand, the macroscopic displacement (volumetric sweep) efficiency of water is much better than CO₂. Therefore, the oil RF and oil production rate of miscible CO₂-WAG flooding are increased by improving the microscopic and macroscopic displacement efficiencies.

It can be concluded that among the three miscible CO₂-WAG flooding experiments with the WAG ratios of 1:1, 2:1, and 1:2 (experiments 3, 6, and 7), experiment 6 has the best overall performance with respect to its high oil RF, high oil production rate, and low consumption of CO₂. Hence, the miscible CO₂-WAG flooding with the WAG ratio of 2:1 is suitable in this study.

Figure 9 Comparison of oil RF for WAG ratios of 1:1, 2:1, and 1:2.

4.3 Oil RF and CO₂ Consumption

The oil RF in each WAG cycle of five miscible CO₂-WAG flooding experiments (experiments 3–7) are summarized in Table 4. Also, the oil RF of all seven core flooding experiments are plotted and compared in Figure 10. Considering Table 4 and Figure 10, the oil RF of the first two cycles of experiments 3–7 are 40.3%, 76.4%, 78.6%, 73.0%, and 58.1%, respectively. A large amount of the heavy oil is produced in the first two cycles in the miscible CO₂-WAG flooding experiments except in experiment 3. The oil RF of the first two WAG cycles and its percentage in the total oil RF of experiment 3 were the lowest because its WAG slug size was 0.15 PV. After the first two WAG cycles in this experiment, a large amount of the residual oil (44.0%) was recovered in the next three WAG cycles. However, experiment 6 with the slug size of 0.15 PV at the WAG ratio of 2:1 had the highest ultimate oil RF and was the most efficient CO₂-WAG flooding method. In this experiment, the injected water can effectively control the mobility of CO₂.

Miscible continuous CO₂ and CO₂-WAG floodings resulted in an unequal amount of cumulative CO₂ injections for each flood. In order to normalize the recoveries, the Tertiary Recovery Factor (TRF) for each experiment was determined. In the literature, the TRF is defined as the percentage of the Residual Oil in Place (%ROIP) divided by the cumulative PV of CO₂ injected (Kulkarni and Rao, 2005). The measured TRF of the miscible continuous CO₂ flooding (experiment 2) and the miscible CO₂-WAG flooding (experiment 6, the most efficient CO₂-WAG flooding method) are shown in Figure 11. As seen in this figure, the miscible CO₂-WAG flooding significantly reduces the CO₂ consumption and enhances the oil RF compared to the miscible continuous CO₂ flooding. On the other hand, gross CO₂ utilization factor for each experiment can be determined. In the literature, the gross CO₂ utilization factor is defined as the volume of CO₂ injected under standard conditions to produce a barrel of oil (Mscf/STB) (Merchant, 2010). The injected CO₂ volumes in experiments 1–7 were equal to 0.00, 2.25, 1.05, 1.00, 1.00, 0.75, and 1.50 PV and the corresponding ultimate oil RF were equal to 37.7%, 61.5%, 84.3%, 82.9%, 78.6%, 93.4%, and 83.7%, respectively. According to the above experimental data, the gross CO₂ utilization factors in experiments 1–7 were approximated to be 0.0, 25.5, 8.7, 8.2, 9.9, 5.8, and 13.0 Mscf/STB. As mentioned in Section 4.3, from the comparison of two miscible CO₂-WAG flooding experiments with the slug sizes of 0.15 and 0.25 PV, the optimal method was selected based on the ultimate oil RF. According to proximity of the oil RF in two experiments and the high CO₂ utilization factor of experiment 3 compared to experiment 4, it is better to be considered the economic conditions in comparing the two experiments. In general, experiment 6 with the slug size of 0.15 PV at the WAG ratio of 2:1 had the highest ultimate oil RF (93.4%), the lowest amount of CO₂ consumption (0.75 PV), and the least CO₂ utilization factor (5.8 Mscf/STB). Therefore, the operating parameters of a CO₂-WAG flooding process, such as its slug size and WAG ratio must be optimized before it is used in a desired oil reservoir.

Figure 10 Comparison of oil RF of seven core flooding experiments.

Figure 11 Comparison of TRF for miscible continuous CO2 flooding and miscible CO2-WAG flooding.

Conclusion

In this research, several slim-tube experiments were done to determine the MMP between the dead oil sample of Sarvak formation and CO₂ at different displacement pressures and the constant reservoir temperature of 96.1 °C. The MMP of 25.92 MPa was determined by plotting the oil RF after 1.2 PV of CO₂ injected versus displacement pressure. A total of seven core flooding experiments were performed by using the core samples of Sarvak formation to investigate the performance of the miscible CO₂-WAG flooding process. First, the different flooding methods were studied and compared, i.e., water flooding, miscible continuous CO₂ flooding, and miscible CO₂-WAG flooding. The results showed that the miscible CO₂-EOR process is capable of mobilizing the heavy oil and achieving a high and significant oil RF in the Sarvak formation. This is because under the miscible conditions, the IFT between CO₂ and oil is zero which leads to a high capillary number and microscopic displacement efficiency. The miscible CO₂-WAG flooding has a higher oil RF than the miscible continuous CO₂ flooding and the water flooding by better controlling the mobility of CO₂ and delaying the CO₂ BT. Next, different WAG slug sizes and WAG ratios of the miscible CO₂-WAG flooding were examined and compared. The results also showed that a smaller WAG slug size of 0.15 PV is preferred in the miscible CO₂-WAG flooding. The optimum WAG ratio of the miscible CO₂-WAG flooding for the Sarvak formation is approximately 2:1. In addition, more than 50% of the heavy oil is produced in the first two WAG cycles. The miscible CO₂-WAG flooding has a higher oil production and a less CO₂ consumption than the miscible continuous CO₂ flooding. This means that a CO₂ utilization factor of the miscible CO₂-WAG flooding is lower than the miscible continuous CO₂ flooding. Hence, the miscible CO₂-WAG flooding is considered to be the best CO₂-EOR flooding process in this formation.

Abbreviations

CO₂-WAG: Water-Alternating-CO₂

EOR: Enhanced Oil Recovery

MMP: Minimum Miscibility Pressure

IFT: Interfacial Tension

BT: Breakthrough

OOIP: Original Oil in Place

RF: Recovery Factor

PV: Pore Volume

BV: Bulk Volume

API: American Petroleum Institute

TDS: Total Dissolved Solids

BPR: Back-Pressure Regulator

HPLC: High Performance Liquid Chromatography

TRF: Tertiary Recovery Factor

ROIP: Residual Oil in Place

References

All Tables

All Figures

	Figure 1 Compositional analysis results of dead oil sample.
In the text

	Figure 2 Schematic diagram of slim-tube apparatus.
In the text

	Figure 3 Schematic diagram of core flooding apparatus.
In the text

	Figure 4 Oil RF versus displacement pressure in slim-tube experiment.
In the text

	Figure 5 Comparison of oil RF and oil production for water flooding and miscible continuous CO2 flooding.
In the text

	Figure 6 Oil RF and oil production of miscible CO2-WAG flooding.
In the text

	Figure 7 Comparison of oil RF for water flooding, miscible continuous CO2 flooding, and miscible CO2-WAG flooding.
In the text

	Figure 8 Comparison of oil RF for WAG slug sizes of 0.15, 0.25, and 0.50 PV.
In the text

	Figure 9 Comparison of oil RF for WAG ratios of 1:1, 2:1, and 1:2.
In the text

	Figure 10 Comparison of oil RF of seven core flooding experiments.
In the text

	Figure 11 Comparison of TRF for miscible continuous CO2 flooding and miscible CO2-WAG flooding.
In the text