Using Polymer Alternating Gas to Enhance Oil Recovery in Heavy Oil

CO2 has been used to recover oil for more than 40 years. Currently, about 43% of EOR production in U.S. is from CO2 flooding. CO2 flooding is a well-established EOR technique, but its density and viscosity nature are challenges for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. So water-alternating-gas (WAG) method was used to control the mobility of CO2 and improve sweep efficiency. However, WAG process has some other problems in heavy oil reservoir, such as poor mobility ratio and gravity overriding. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests a new EOR method--polymer-alternating gas (PAG) process. The process involves a combination of polymer flooding and CO2 injection. To confirm the effectiveness of PAG process in heavy oils, a reservoir model from Liaohe Oilfield is used to compare the technical and economic performance among PAG, WAG and polymer flooding. Simulation results show that PAG method would increase oil recovery over 10% compared with other EOR methods and PAG would be economically success based on assumption in this study. This study is the first to apply PAG to enhance oil recovery in heavy oil reservoir with highly heterogeneous. Besides, this paper provides detailed discussions and comparison about PAG with other EOR methods in this heavy oil reservoir.


Introduction
Although CO 2 flooding is a well-established EOR technique, its density and viscosity nature is a challenge for CO 2 projects. As low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir, and low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. In heterogeneous reservoirs with high-permeability zones and natural fractures, the condition is even worse.
Almost all commercial miscible gas injection projects used WAG to control mobility of gas and alleviate fingering problems. Recovery of WAG is better than gas injection, and 80% of commercial WAG projects in the US are economic. However, recent studies show that most of the fields could not reach the excepted recovery factor from the WAG process, especially, for reservoirs with highpermeability zones or with natural fractures (Christensen et al. 2001).
To overcome the issues of gas breakthrough and gravity segregation, we proposed a new combination method, termed as PAG, which combines the features of CO 2 flooding and polymer flooding. Coupling of polymer with CO 2 is expected to improve the efficiency of WAG. The main feature of PAG is that In this paper, a heterogeneous reservoir model was built with using a field case geological model from Liaohe Oilfield in China. Field scale simulations are performed taking into account of reservoir heterogeneity and heavy oil fluid properties. In the following section, the reservoir and fluid model were described. Then performance between PAG and other EOR methods, including continuous CO 2 , water alternating gas and polymer flooding, were compared. Finally, economic feasibility of PAG was studied.

Reservoir Model
A reservoir model was built based on a geological model from Liaohe Oilfield. The reservoir sector model size is 3000 ft × 2278 ft × 40 ft in X-Y-Z direction. The reservoir is thick enough to see the effect of gravity segregation. The reservoir is located 3,000 ft beneath the surface and has no dip. The reservoir is heterogeneous and consists of a sandstone formation. Figure 1 shows the reservoir model. The location of injection and production wells are shown in Figure 1 in the model. In all simulations the injection rate is fixed at 0.1 PV/yaer for gas injection well and 0.1 PV/year for water injection well, and the bottom-hole pressure (BHP) at the producers is fixed at 200 psi and at the injectors is fixed at 3,100 psi in the EOR process. Table 1 presents the input of reservoir rock and fluid properties that were used in the simulation study.

Parameters for Polymer Flooding
Rock adsorption and polymer viscosity are two important parameters for polymer flooding. The correlation between polymer viscosity and polymer concentration is shown in Figure 2. Figure 3 shows a correlation between polymer concentration and polymer adsorption. The maximum adsorption is 130 ug/ (g rock). Residual resistance factor (RRF) value of 2.0 at 1,000 ppm was assumed in this study.

Simulation Results and Discussion
Five different development methods including water flood, polymer flood, continue gas injection (CGI), WAG, and PAG, were studied. The results were compared, including recovery factor, oil rate, GOR, saturation profile, etc. The amount of water and gas injection, oil and gas production, and oil recovery are listed in Table 3.

Waterflooding (WF)
Nine injectors in the reservoir simulation model inject fluid (water/gas) with a maximum injection pressure of 3,100 psi, starting in 2014. Prior to the water flooding, the reservoir oil saturation is about 0.55. After 18-year's water flooding, the oil saturation is reduced to 0.46. Figures 4.a-4.c indicates that remaining oil saturation in Layer 1 is much higher than that in Layers 5 and 10. The main mechanism behind it is gravity effect-water has higher density than oil, so that water would go to lower layers and bypass upper layers, which leads to poor sweep efficiency.  The total oil rate from 6 producers in the pilot region is show in Figure 5. It indicates steep oil production decline is due to quick breakthrough of the injection water. The oil recovery factor is about 14.2% with high water cut of 98%, as shown in Figure 6 and Figure 7.

Polymer Flooding (PF)
In the polymer flooding process, polymer was added to the water injection wells with a concentration of 1,000 ppm in the simulation model. After polymer flooding, the remaining oil saturation is reduced to 0.39 (Figure 8). Comparing Figures 4.d-4.f with Figures 4.a-4.c, the results clearly show that oil saturation in Layer 1 after polymer flooding is much lower than that after water flooding. In other words, upper layers have more remaining oil saturation than lower layers. Figure 5 shows that highest oil rate after polymer flooding is 145 bbl/day, which is 2 times higher than oil rate before polymer flooding. Figure 6 shows that water cut decreases from 95% to 65%. The oil recovery factors after polymer flooding is also shown in Figure 7. It shows polymer flooding can reach oil recovery factor to 23.16%, while water flooding only gets 14.20%.

Continuous Gas Injection (CGI) with CO 2
In continuous gas injection process, injecting CO 2 continuously with well constraint of maximum rate of 1.5 mmscfd through 9 injectors, and a maximum injection well pressure of 3,100 psi. Figures 4.g-4.i show that gas only swept the upper part of reservoir and left large un-swept area in the lower layers, which is due to the gravity override of lower CO 2 density. As shown in Figures 5 and 6, CGI could reach a peak oil rate of 246 bbl/day and reduce water cut to 20%. The oil recovery factor after CGI is 20%, which is higher than after water flooding (Figure 7). CGI would result in early gas breakthrough, as indicated by Figure 9 which shows gas-oil-ratio increases sharply after 6-month's CO 2 injection.

Water Alternating Gas (WAG)
To alleviate the early gas breakthrough and low swept efficiency of CO 2 flooding, WAG process is implemented and investigated. In the WAG process, water and CO 2 is injected alternatingly at 1:1 ratio and 6 months per cycle, which means 3 month of water and 3 month of CO 2 injection. As shown in Figures 5 and 6 WAG could reach a peak oil rate 225 bbl/day and reduce water cut to 60%.
According to Figure 7, WAG process obtains oil recovery of 21.1%, which is higher than water flooding because of CO 2 miscibility with water conformance control. WAG significantly reduces gas production rate and alleviates gas early breakthrough, which can be demonstrated in Figure 8 as there is much lower gas-oil-ratio after WAG than after CGI. that Layer 1 has lower oil saturation in CGI process than in WAG process, but Layers 5 and 10 have higher oil saturation in CGI process than in WAG process. It indicates WAG improves CGI performance. However, it also shows that gas swept the upper part of reservoir and still left large unswept area in the lower layers because of gravity override caused by low CO 2 density.

Polymer Alternating Gas (PAG)
To overcome these problems, the combination of polymer flooding and CO 2 flooding is used. It has advantages of CO 2 flooding and polymer flooding, solubility of CO 2 injection, and mobility control of polymer injection. In a PAG process, polymeric solution is injected into reservoir instead of water in WAG process. The polymer concentration 1000 ppm is used based on reservoir permeability and heterogeneous during PAG process. The simulation result shows that peek oil rate after PAG is 370 bbl/day, which is 50% higher than WAG and 190% higher than after polymer flooding. Water cut also can be decreased from 95% to 28%. Figure 8 shows that GOR in PAG is only one eighth of CGI process and one fourth of WAG process. As shown in Figure 7, PAG achieves the highest oil recovery of 33.65%. The oil recovery enhanced by PAG is 43% more than polymer flooding and 57% more than WAG process. The additional recovery by PAG resulted from mobility ratio control. Figures 4.m-4.o depicts the oil saturation distribution of PAG process in the end of production. Layer 1 has higher remaining oil saturation in PAG process than that in WAG process, which means more gas is injected to lower layers in PAG so that poor sweep efficiency is improved. Layers 5 and 10 have lower remaining oil saturation in PAG process than that in WAG process.