Improving Oil Recovery by Cold CO 2 Injection: A Simulation Study

International Journal of Petroleum and Geoscience Engineering (IJPGE) 1 (3): ISSN 2289-4713 Academic Research Online Publisher Research Article Improving Oil Recovery by Cold CO 2 Injection: A Simulation Study ZakariaHamdi*, MariyamniAwang Petroleum Engineering Department, UniversitiTeknologi PETRONAS (UTP), Tronoh, Malaysia * Corresponding author. Email Address: zakaria_g01743@utp.edu.my A b s t r a c t Keywords: Enhanced Oil Recovery, Low Temperature CO 2, Liquid CO 2 Injection, High temperature Reservoirs, Thermal compositional Model CO 2 injection has been used for many years and it is accepted as a beneficial tertiary recovery method. However, there are very limited studies of liquid CO 2 injection process and its effect on reservoir properties. The objective of this research is to investigate the effects of liquid CO 2 injection on temperature distribution, fluid properties and oil recovery in a high temperature reservoir. A thermal compositional model is used to simulate the behavior of the reservoir in terms of viscosity, front movement and temperature. The main results of the study show that the temperature of the reservoir is affected by injection temperature and its rate; also, the effect of low temperature on viscosity cannot eliminate viscosity reduction by CO 2. The recovery is doubled (12.81% increase) and mainly is due to liquid CO 2 viscosity reduction by 6 times. Accepted:21September2013 Academic Research Online Publisher. All rights reserved. 1. Introduction Primary and secondary methods for oil production covers one third of the initial oil in place. During life of a well, there is a time that price of the oil is less than its cost in markets. In usual scenarios the oil production is stopped. But in the last decades, the decline in exploration of new reservoirs has forced the oil companies to develop enhanced oil recovery (EOR) methods. Thermal, chemical and gas flooding are three major EOR methods, which have been developed during last years [1]. Use of CO 2 for EOR and sequestration processes not only reduces greenhouse emissions but also gives economic benefits [2]. In CO 2 -EOR the main purpose is to maximize oil recovery with the

minimum quantity of CO 2 while for sequestration a maximum amount of CO 2 is aimed to be stored [3]. Continuous CO 2 injection is usually used for reservoirs suitable for gravity stable displacement [4, 5].Carbon dioxide injection has been recommended for EOR in three methods of displacement including miscible, near miscible or immiscible forms after water flooding as an EOR method or even as a secondary displacement method [6]. The EOR mechanism involving CO 2 flooding include swelling of the oil, viscosity reduction, oil extraction and solution gas drive that have been analyzed thoroughly in last decades [7-11]. For miscible injection, the volume of oil swells, its viscosity is reduced, and there will be no interfacial tension. This means higher sweeping and better displacement that will result in higher recovery of the crude inside the reservoir [12]. But minimum miscibility pressure (MMP) sometimes is much higher than reservoir pressure. Injecting CO 2 for enhancing oil recovery will cause a lower MMP of the mixture and becomes a beneficial tool for the flooding. But in numerous reservoirs, injection of CO 2 will not cause miscibility achievement. In the other hand, low temperature of the system will result in lower MMP and miscible flooding. So injecting low temperature CO 2 will act as a double agent for reduction of MMP; i.e. presence of CO 2 and low temperature. Carbon dioxide has a relatively high density and has liquid-like behavior. But its viscosity is depending on pressure and temperature [13]. In this paper cold CO 2 refers to the temperature less than critical temperature of CO 2 i.e. 87.7 F (Figure 1). Using cold liquid CO 2 for continuous injection may decrease the MMP significantly. The slim tube measurements reported in several literature show that low temperature CO 2 injection can achieve high displacement efficiency of more than 90% [14]. The most common explanation for high displacement efficiency by liquid CO 2 is that the CO 2 -rich phase formed in the reservoir will extract a certain range of hydrocarbons in the reservoir i.e. selectivity of liquid phase of CO 2 [15]. In this study, the hypothesis states that if liquid CO 2 is being used, even if it is injected to a hot reservoir (+200 F), there will be a part of the reservoir that after certain amount of injection and time, equilibrium with the injection temperature will be achieved, and this cooling ultimately will result in complete miscible displacement and high recovery factor. In this simulation, the displacement considered to be miscible as it is used liquid CO 2 at the temperature and pressure conditions of the reservoir. 168 Page

Fig. 1.CO 2 phase diagram [16] 2. Theory and Methodology To examine this hypothesis, a simulation is designed. For accurate results, it is necessary that both compositional simulation and thermal simulation of the crude is used. Eclipse simulation package is selected as a candidate to perform this study. When CO 2 is injected to the reservoir with different temperature than the reservoir, the heat transfer plays an important role between the phases of the fluids and has a direct impact on the recovery. It includes the heat transfer between injected fluid, the reservoir fluids, and reservoir rock. When CO 2 enters the reservoir, it vaporizes due to contact with a hot fluid. But after a while, this forms a layer that will protect the rest of injecting fluid. This approach will be examined in this paper. A light crude oil is chosen having seven components. The composition is shown in Table 1. By using PVTi package, and using regressions, the PVT properties of the crude are extracted. This is mandatory as the simulator needs it as the input. 169 Page

Table 1: Crude Oil Composition # Composition Mole Fraction % 1 CO 2 0 2 C 1 45.4 3 C 2 9.08 4 C 3 5.77 5 C 4+ 3.89 6 C 5+ 2.84 7 C 6+ 33.02 The injection fluid was chosen liquid CO 2 having 41 F temperature injecting at a pressure of 5900 psi. The injection scheme is continuous CO 2 injection. The reservoir properties are chosen in worst case scenario, where high temperature of the reservoir would resist the liquid CO 2. The pressure is chosen high for both reservoir and injection so that minimum miscibility is achieved and no gas cap would be present. The water oil contact is chosen in much deeper layers so only the effect of the injection process on the crude is studied. The porosity is taken 25% and the permeability is taken 400 md. Other initial reservoir parameters are shown in Table 2. 3. Results and discussion The simulation is run for 10 years. Viscosity and density of the fluids inside the reservoir can be analyzed with respect to distance and depth for each block, especially when CO 2 contacts and mixes with the crude oil. This helps to study the effect of both CO 2 and temperature on mobility of the crude oil that is shown later. The analysis of temperature change inside the reservoir is the most important result of the simulation of the process. It reveals the change in reservoir temperature in each block helping to understand the phase of CO 2 and miscibility displacement inside the reservoir for each block. Finally, the recovery factor can be obtained from the model, and the influence of low temperature on the recovery can be studied and compared to isothermal CO 2 injection. 170 Page

Table 2: Initial parameters of the reservoir PARAMETER VALUE Reservoir temperature ( F) 215 Injection temperature ( F) 41 Initial water saturation (%) 19.25 Oil saturation (%) 80.75 Reservoir blocks 30x30x10 Reservoir block size (ft) 30x30x10 Porosity (%) 25 homogeneous Permeability (md) 400 homogeneous Number of oil components 7 Top layer depth (ft) 3050 Injection pressure (psi) 5900 Reservoir initial pressure (psi) 5500 Oil production rate (bbl/day) 500 CO 2 injection rate (Mscf/day) 2000 Fig. 2. Oil viscosity of blocks 10-10-01 (Top), 10-10-05 (Middle) and 10-10-10 (Bottom) Figure 3 shows the temperature change along the reservoir in one third of the distance between injection and production point. It can be seen that the temperature of reservoir will be replaced by the injection temperature in 1500 days. The start of this change varies by the depth, starting at the bottom 171 Page

of the blocks. In the bottom the change starts after 200 days while in the middle and the top of the pinpointed blocks the decrease in temperature starts from 800 days. Fig. 3. Temperature profile of blocks 10-10-01 (Top), 10-10-05 (Middle) and 10-10-10 (Bottom) This change of temperature can be even up to production well (Figure 4 and Figure 5). In blocks near the injection well the temperature of the reservoir is changed in less than 500 days and replaced by injection temperature. But in some blocks with higher distance from injection, the temperature change is much less. Near the production well, the temperature change is also significant but not reaching the injection temperature. The 3D representation of the temperature change is shown in Figure 4 and Figure 5. As it can be realized, the temperature change is much higher in bottom of the reservoir than the top. It is due to the movement of CO 2 inside the reservoir because of density difference of CO 2 and crude oil. Further analysis of this model can lead to prove the possibility of lowering the reservoir temperature by continuous CO 2 injection. Fig. 4. Top view of temperature distribution in different time steps 172 Page

Fig. 5. Bottom view of temperature distribution in different time steps Formation of CO 2 front and its phase also can be seen by the model. Mole fraction analysis of CO 2 in both liquid and supercritical form will trace the movement and presence of CO 2 in each block. The movement and the phase of the front from the injection point toward the production well can be observed in Figure 6 and Figure 7. As it can be realized, the CO 2 front is a thin layer of supercritical form. Figure 8 shows the supercritical CO 2 mole fraction in one third of the distance from the injection toward the production wells in different reservoir depths. Comparing top and bottom of the reservoirs shows that the front is thinner at the top and stretches when it is in the bottom of the reservoir moving towards the production well. So the movement of CO 2 front is faster in the bottom and slower on the top of the reservoir. Fig. 6. Top view for CO 2 front movement inside the reservoir in different time steps 173 Page

Fig. 7. Bottom view for CO 2 front movement inside the reservoir in different time steps Fig. 8.CO 2 vapor mole fraction of blocks 10-10-01 (Top) and 10-10-10 (Bottom) Figure 9 shows the liquid CO 2 distribution from the injection toward production well in different time steps by use of its mole fraction. It shows that the liquid CO 2 will sweep the crude toward the production and it remains liquid inside the reservoir and accumulated in the radius near the wellbore. The radius is dependent on the rate and duration of injection as our case is reaches 300ft radius from the injection well. As can be seen, movement of liquid CO 2 is faster in the bottom of the reservoir than on top. It can be referred as the result of density difference of crude oil. This can be considered as another benefit of cold CO 2 injection. Reaching 1 in mole fraction means complete sweep by CO 2 in mentioned blocks and presence of CO 2 only on that specific block. As expected, it showed very good recovery of 24.71%. Injection temperature affected the reservoir temperature. This illustrates higher percentage of recovery than when CO 2 is in supercritical form (215 F, i.e. isothermal injection), having a simulated recovery of 11.90% (as shown in Figure 10). 174 Page

Fig. 9. Liquid CO 2 presence and movement inside the reservoir Fig. 10.Recovery Factor of the simulation of Liquid CO 2 injection in Compare with Supercritical CO 2. 4. Conclusions and Future Directions This study has attempted to evaluate the effectiveness of CO 2 liquid injection for the purpose of higher oil recovery achievement. A simulation study of a liquid CO 2 injection has been performed to study some of the important parameters involved in displacement. As expected, usage of liquid CO 2 resulted in 12.81% increase in recovery factor than of supercritical form. A part of the reservoir reached a local equilibrium temperature according to the injection temperature and the rate of injection; while other parts of the reservoir remained almost intact. CO 2 remained liquid at all the time except for the front of the injection fluid (supercritical CO 2 ) that was pushed by the liquid CO 2 and displaced the crudes toward the production well. This would help in aiming sequestration as an extra benefit of continuous CO 2 injection. Also being liquid illustrated higher amount of CO 2 injected. Viscosity of the mixture reduced significantly and showed that presence of temperature drop could not eliminate the effect of CO 2 on viscosity of the oil. That increased the mobility of the oil significantly. 175 Page

Liquid CO 2 can be highly beneficial in crudes with high MMP as it can be miscible with lower pressures and remains miscible for a longer injection period. Using liquid CO 2 is effective even with high temperature reservoirs. This can open a new view for CO 2 -EOR and sequestration studies in future. Future work can include combining EOR and sequestration purposes to measure liquid CO 2 capability for storage as well as recovery increase. Acknowledgement: The author would like to thank Universiti Teknologi PETRONAS for its assistantship support and software licensing of Eclipse. Reference: [1] Moritis G., "EOR Continues to Unlock the Oil Resources," Oil and Gas Journal, 2004; 45-52 [2] Espie T., "A New Dawn for CO 2 EOR," presented at the International Petroleum Technology Conference, Doha, Qatar, 2005. [3] PamukcuG. F. Y. Z., Simulating Oil Recovery During CO 2 Sequestration Into a Mature Oil Reservoir, Canadian International Petroleum Conference, Jun 12-14, 2007, Calgary, Alberta. [4] Bellavance J. F. R., "Dollarhide Devonian CO 2 Flood: Project Performance Review 10 Years Later," presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 1996. [5] PooleE. S., "Evaluation and Implementation OfCO 2 Injection at the Dollarhide Devonian Unit," presented at the Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 1988. [6]Lindeberg E. and HoltT., "EOR by Miscible CO 2 Injection in the North Sea," presented at the SPE/DOE Improved Oil Recovery Symposium, Tulsa, Oklahoma, 1994. [7]KlinsM. A., Carbon dioxide flooding: basic mechanisms and project design: D. Reidel publishing company, 1984. [8]MunganN., "Carbon Dioxide Flooding-fundamentals," Journal of Canadian Petroleum Technology, vol. 20, 01/03/1981 1981. [9] HolmL. W. and JosendalV. A., "Mechanisms of Oil Displacement By Carbon Dioxide," SPE Journal of Petroleum Technology, 1974; 26; 1427-1438. [10] Miller J. S. and JonesR. A., "A Laboratory Study to Determine Physical Characteristics of Heavy Oil AfterCO 2 Saturation," presented at the SPE/DOE Enhanced Oil Recovery Symposium, Tulsa, Oklahoma, 1981. [11] SimonR., RosmanA., and ZanaE., "Phase-Behavior Properties of CO 2 - Reservoir Oil Systems," Society of Petroleum Engineers Journal, 1978; 18; 20-26. [12] LakeL. W., " Improved Oil Recovery," Prentice-Hall Englewood Cliffs, 1989; 234. [13] SohrabiM., JamiolahmadyM., and QurainiA. A., "Heavy Oil Recovery by Liquid CO 2 /Water Injection," presented at the EUROPEC/EAGE Conference and Exhibition, London, U.K., 2007. 176 Page

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