The Potential of Immiscible Carbon Dioxide Flooding on Malaysian Light Oil Reservoir

Transcription

1 International Journal of Petroleum and Geoscience Engineering (IJPGE) 1 (1): 1-11, ISSN xxxx-xxxx Academic Research Online Publisher Research Article The Potential of Immiscible Carbon Dioxide Flooding on Malaysian Light Oil Reservoir S. Majidaie a, A. Khanifar a, Isa M. Tan a, M. Onur a a EOR Center, UniversitiTeknologi PETRONAS, Malaysia * Corresponding author. address:saeedan8@gmail.com ARTICLE INFO Article history Received:1March Accepted:13March Keywords: EOR Immiscible CO 2 Phase behavior A b s t r a c t Immiscible CO 2 flooding is one of interesting methods in enhanced oil recovery (EOR) which is technically and economically feasible in many oilfields around the world. The potential of immiscible CO 2 flooding in selected Malaysian oilfield was investigated through laboratory experiments. The live oil sample is prepared in recombination cell under reservoir conditions. The CO 2 -oil phase behavior is investigated through PVT cell and the electromagnetic viscometer and densitometer are used. The experimental results are verified by correlation and fluid simulation. The results show clearly the effect of CO 2 addition on the fluid properties. As expected by CO 2 addition the viscosity of oil reduced the saturation pressure and density of oil increased and oil significantly swelled. Academic Research Online Publisher. All rights reserved. 1. Introduction In recent years, CO 2 flooding projects have grown rapidly around the world. It is the second largest process after thermal methods in heavy oil field [1]. CO 2 gas injection is more desirable compare to other gases due to lower injectivity problems, lower formation volume factor, abundance of reserves and higher incremental oil recovery [2]. Furthermore, CO 2 has low miscibility pressure (multi-contact and first contact miscibility) compare to other miscible gas [3,4]. Such behavior allows the application of CO 2 flooding to different range of crude oil. CO 2 can be used in immiscible conditions for depleted reservoir with low pressure which is not technically or economically feasible to increase the reservoir pressure. [5, 6]. At immiscible conditions, there is a great chance of improvement of oil recovery because CO 2 can considerably reduce the oil viscosity and swell the oil volume. Therefore, it is crucial to 1 Page

2 understand the physical and chemical interactions between CO 2 and reservoir oil. CO 2 solubility cause a viscosity reduction which helps to improve the mobility ratio and hence better macroscopic displacement efficiency [7]. The swelling is defined as an increase in volume of a crude oil when saturated with CO 2. This mechanism causes oil droplets to be removed from pore spaces and hence, a lower residual oil saturation and better microscopic displacement efficiency is expected [8]. The CO 2 -oil phase behavior study is necessary for better understanding of these parameters for a successful CO 2 flooding project. In this study, the effects of CO 2 on oil physical properties are determined by laboratory studies and are verified by a commercial simulator. 2. CO 2 Oil interaction parameters 2.1. Solubility CO 2 solubility is a function of reservoir conditions like temperature and pressure and oil properties like saturation pressure, oil gravity, and oil composition [9]. Solubility increases with pressure and oil gravity and decreases with tem perature. CO 2 phase diagram is another important parameter affecting CO 2 solubility. Gaseous CO 2 is more soluble in crude oil than liquid CO 2. Therefore, for tempera-tures less than the critical temperature (Tc), CO2 (31.1 C), where CO 2 is gas, the CO 2 solubility increases with pressure up to the liquefaction pressure, and then flattens off at pressures higher than the liquefaction pressure and becomes less sensitive to the pressure [10] Oil swelling Oil swelling is one of the properties of CO 2 that makes it a useful EOR agent. It is defined as the ratio of CO 2 -saturated oil volume at the reservoir temperature and pressure to the oil volume at the reservoir temperature and oil bubble point pressure (P b ). Swelling factor shows how much the original oil will swell in the presence of CO 2. The residual oil left in the reservoir after flooding is inversely proportional to the swelling factor, i.e. the greater the swelling, the less stock tank oil is left behind in the reservoir. The swelling factor is mainly a function of CO 2 solubility [11]. Hence, the liquefaction pressure affects the swelling factor. Furthermore, as CO 2 solubility in light oil is higher than that in heavy oil, the lighter oil swells more than the heavier oil. Besides CO 2 solubility, the swelling factor is also a function of the molecular size of oil molecules [12]. 2 Page

3 2.3. Density Generally, the CO 2 solubility has a small effect on oil density and this effect is more obvious in light oils compared to heavy oils. There is an increase in oil density due to CO 2 solubility increase [13] Viscosity Increasing the CO 2 solubility causes the oil viscosity to decrease severely and increases the oil mobility, this results in an increase in oil recovery. The CO 2 -Oil viscosity decreases with the saturation pressure up to the liquefaction pressure, at temperatures less than T C, CO 2, then flattens off and decreases slightly at pressures higher than liquefaction pressure. At higher pressures, the viscosity begins to increase again because of the effect of the pressure and oil compressibility [14]. The mixture viscosity reduction is higher for more viscous oil (heavy oils) than for lower viscous oil (light oils) [15]. Many studies have reported that the mixture viscosity is generally a function of its composition [9]. 3. Materials and experimental procedures In this study crude oil was collected from a Malaysian light oil reservoir with potential for the application of immiscible CO 2 flooding. The stock tank oil (STO) properties were measured and are presented in Table 1. The composition of dead oil is presented in Table 2. The API gravity of the crude oil is The estimated reservoir pressure and temperature are 1400 psi and 100 C, respectively. The density of the STO at 15 O C is 836 kg/m Reconstitution of reservoir fluid The dead crude oil, pure carbon dioxide (CO 2 ), and pure methane (CH 4 ) were physically recombined in the laboratory using the recombination cell to result in a reservoir fluid (live oil). The recombination cell is based on high pressure, high temperature cell in which oil and gas are injected at pre-defined volume, stirred together, heated at a desired temperature and pressurized at pressure above the saturation pressure for few hours to give a homogeneous mixture of the reservoir fluid. The composition of the live oil is presented in Table 2. Once the recombination was complete, the oil was pressured to well above the bubble point and a constant mass expansion (CME) test was conducted to measure the bubble point. Its saturation pressure was 1850 psi at 100 C, which is 450 psi higher than the current reservoir pressure of 1400 psi. 3 Page

4 Table.1: The stock tank oil (STO) properties. Parameter Value Temperature 15 OC API Gravity 37.7O Density at 1 atm Specific (kg/m3) Gravity Asphaltenes Molecular mass Mass% Pour (g/mol) Point 33 OC Once the sample was satisfactorily recombined, its viscosity was measured in an electromagnetic viscometer and density in a digital densitometer, both as functions of pressure (above the saturation pressure), which made it possible to determine the values at saturation pressure by a short extrapolation. The major physical properties, including viscosity and density at the saturation pressure are presented in Table 3. Table.2: The Composition of Dead and Live Oil Samples. Component MW Dead Oil Live Oil CO C nc C C C C C C TOTAL Phase behavior measurements of CO 2 -saturated oil The solubility of CO 2 in the oil depends on reservoir conditions and on oil properties. The CO 2 reservoir fluid equilibrium liquid properties for specific oil at the reservoir conditions are important for the optimization of an immiscible CO 2 process. The experimental apparatus consists of a PVT cell. Approximately 50 cc of the recombined fluid was transferred into the preheated PVT cell. CO 2 was added to the reservoir fluid in a series of steps from 20 to 80 mole percent of the fluid sample. At each addition, homogeneity of the mixture was achieved by magnetically stirring it until the PVT cell pressure was stabilized at the set value. Constant Composition Expansion (CCE) tests were conducted after adding each mole percent of CO 2. The procedure used is outlined in the following: 1. A sample of live oil was charged into PVT cell system. 4 Page

5 2. A predetermined volume of CO 2 gas was charged into the cell to bring the saturation pressure up to the next level. The amount of charge was calculated to be a certain percentage of the oil. 3. After a CO 2 addition, the pressure in the cell was raised well above the estimated saturation pressure, and the cell s contents were mixed until a single phase was obtained. 4. Conduct a CME test to determine saturation pressure. 5. Raise the pressure again above the saturation pressure to mix phases 6. A sample of CO 2 added-oil was transferred to electromagnetic viscometer to measure the viscosity. 7. Fluid densities are measured in a digital densitometer at reservoir temperature. Three more increments of gas were introduced into the cell, and the same fluid properties were measured after each addition. 6. CO 2 -oil physical properties correlation Based on literature review, for all the physical properties like CO2 solubility, oil swelling due to CO2, CO2-oil density, and CO2-oil viscosity, Emera and Sarma[16] correlations can yield a more accurate predictions with lower errors compare to other available correlations. Emera and Sarma emphasized that these correlations can be applied to a wide range and conditions of reservoir. 7. Fluid modeling The conventional software is used for developing a fluid model base on equation of state (EOS) selection, fluid characterization, regression and tuning the EOS parameters, and then prediction under different situations. The Peng-Robinson is chosen as suitable EOS and a data set has been prepared to characterize the fluid by defining compositions of components up to C 10 and pseudo-components describing the C 11+ fraction. From the Table 2, the composition data to C 10 has been used, and a plus fraction splittingcalculation has been specified with the C 11+ molecular weight and specific gravity. The plus fraction is split from 5 Page

6 C 11 to C 36+ and then they are lumped into four pseudo components, and the Lee-Kesler critical property correlations are used [17]. After splitting, and updating to reflect the results of the splitting calculation, the equation of state model can now be tuned to any available PVT data via regression. The observed data have been provided from the lab experiments: bubble point pressure, API gravity, live oil molecular weight, constant composition expansion and differential liberation. Regression has been carried out on these observed data by tuning regression variables. By adjusting these parameters the EOS is tuned and it can predict the correct phase behavior of the fluid [17]. Swelling Experiment: This experiment provides information on the fluid behavior under gas injection processes. When a gas is injected into a reservoir, it can go into solution and swell the oil, i.e. the volume of the oil becomes larger. Measurements of this effect can be performed as follows. The reservoir oil is loaded in a cell, and the temperature is set at the reservoir temperature. The bubble point of the oil and the corresponding volume are measured. A small amount of injection gas is transferred into the cell. A new saturation pressure is determined and a new saturation volume recorded. This process is repeated until the upper bound of injection-gas concentration is reached or the saturation pressure of the fluid is equal to the estimated injection pressure. A constant composition expansion experiment may be performed for each mixture of injection-gas and oil in the above process [17]. 8. Results and discussion The CO 2 - reservoir fluid properties from experiments, Emera&Sarma correlation and fluid simulation are presented in Table 3, 4 and 5 respectively. The saturation pressure versus CO 2 added data for experiment, correlation and simulation results are presented in Fig. 1. Fig. 1 shows a good match between three different methods is obtained. The saturation pressure increases with CO 2 addition. It means the solubility of CO 2 is a function of pressure. The more CO 2 is dissolved, the higher is the saturation pressure. Figure 2 shows the comparison between the results of three different methods for density by CO 2 addition. According to this graph CO 2 saturated oil densities increases with increasing CO 2 content for selected crude oil. A good match between Emera&Sarma correlation and experimental results is obtained but the equation of state (EOS) shows a certain deviation which can be due to tuning process of the EOS parameters. Probably having more experimental data may help to get a better match. Currently, this is under investigation. 6 Page

7 Table.3: Equilibrium liquid properties OF Live Oil, CO 2 Saturated Oil at 100 O C, Experiment. Fluid CO 2 Added (Mole %) Saturation Pressure (psi) Mixture Density at P sat (lb/ft 3 ) Mixture Viscosity at P sat (cp) Live Oil Swelling Factor CO 2 - saturated Oil Figure 3 shows that viscosity reduces by CO 2 addition. With additions of CO 2 in the oil, the viscosity of the CO 2 -saturated oil decreased substantially as the oil absorbed more CO 2 with increasing saturation pressure. The viscosity of the CO 2 -saturated oil at 100 C ranged from cp (live oil) down to for 80 mol% of CO 2 dissolved in the oil. The magnitude of swelling for light oils is significant which can often be swelled by more than 50% in their original volume. The experimental results indicate that approximately 100% expansion of the reservoir fluid can be expected from experimental results at pressures 3980 psi and the reservoir temperature of 100 C in a CO 2 injection project. Fig. 4 shows the related results. Table.4: Equilibrium Liquid Properties of Live Oil, CO 2 Saturated Oil at 100 O C, EMERA & SARMA Correlation Fluid CO 2 Added (Mole %) Saturation Pressure (psi) Mixture Density at P sat (lb/ft 3 ) Mixture Viscosity at P sat (cp) Swelling Factor Live Oil CO saturated Oil Page

8 Table.5: Equilibrium Liquid Properties of Live Oil, CO 2 Saturated Oil at 100 O C, Fluid Simulation. Fluid CO 2 Added Saturation Pressure Mixture Density Mixture Viscosity Swelling Factor (Mole (psi) at Psat at Psat %) (lb/ft 3 ) (cp) Live Oil CO Fig. 1. The effect of added CO 2 on saturation pressure. Fig. 2. The effect of added CO 2 on oil density. 8 Page

9 Fig. 3. The effect of added CO 2 on oil viscosity. Fig. 4. Swelling factor of CO 2 -oil mixture. 9. Conclusions and Recommendations This study investigated experimentally the effect of CO 2 gas injection in immiscible process on selected Malaysian light oil. The results are verified by correlation and simulation. The results from this study are encouraging the immiscible CO 2 injection as a successful EOR method. The conclusions drawn from this study are as follows: i. CO 2 can easily be dissolved in the selected oil at usual operational pressure range. From 2500 to 3000 psi pressure range, mole % CO 2 can be soluble in the reservoir fluid during CO 2 injection. ii. Also, viscosity of CO 2 -saturated oil reduces from to cp for mole% of CO 2 dissolution at the same pressure range. 9 Page

10 iii. Again, swelling factor changes from 1.07 to 1.22 which means that the fluid volume increases by 7 to 22% more than its original volume. iv. Although a good match is obtained from experiment and correlation for density but the EOS result has deviation which means further experiments are necessary to tune the EOS. v. Immiscible CO 2 flooding seems to be a potentially feasible EOR process for the selected oilfield based on laboratory experiments. Acknowledgment The authors would like to thank our laboratory technician Mr. Riduan for handling PVT experiments and special thanks to EOR center, UniversitiTeknologi PETRONAS for its support on this research. References 1. L Hinderaker. RUTH - A Comprehensive Norwegian R & D program on IOR. European Petroleum Conference, Milan, Italy MM Kulkarni. Immiscible and Miscible Gas-oil Displacements in Porous Media MF Al-Ajmi. Planning Miscibility Tests and Gas Injection Projects for Four Major Kuwaiti Reservoirs. Kuwait International Petroleum Conference and Exhibition, Kuwait City, Kuwait GF Teletzke. Methodology for Miscible Gas Injection EOR Screening. SPE International Improved Oil Recovery Conference in Asia Pacific, Kuala Lumpur, Malaysia, LJ Mohammed-Singh, AK Singhal. Lessons from Trinidad's CO 2 Immiscible Pilot Projects SPE Reservoir Evaluation & Engineering S Sahin. Bati Raman Field Immiscible CO 2 Application--Status Quo and Future Plans. SPE Reservoir Evaluation & Engineering DG Hatzignatiou, Y Lu. Feasibility Study of CO 2 Immiscible Displacement Process In Heavy Oil Reservoirs. Annual Technical Meeting, Calgary, Alberta Page

11 8. ZM Zain. Evaluation of CO 2 Gas Injection for Major Oil Production Fields in Malaysia - Experimental Approach Case Study: Dulang Field. SPE Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia FTH Chung. Recovery of Viscous Oil Under High Pressure by CO 2 Displacement: A Laboratory Study. International Meeting on Petroleum Engineering Tianjin China RA DeRuiter. Solubility and Displacement Behavior of a Viscous Crude with CO 2 and Hydrocarbon Gases. Journal of SPE Reservoir Engineering 1994;9(2): V Sankur. A Laboratory Study of Wilmington Tar Zone CO 2 Injection Project. Journal of SPE Reservoir Engineering 1986;1(1): R Simon, DJ Graue. Generalized Correlations for Predicting Solubility, Swelling and Viscosity Behavior of CO2 -Crude Oil Systems LW Holm, VA Josendal. Mechanisms of Oil Displacement By Carbon Dioxide. Journal of Petroleum Technology 1974;26(12): SL Kokal, SG Sayegh. Phase behavior and physical properties of CO 2 -saturated heavy oil and its constitutive fractions: Experimental data and correlations. Journal of Petroleum Science and Engineering 1993;9(4): GA Rojas, SMF Ali. Dynamics of Subcritical CO 2 /Brine Floods for Heavy-Oil Recovery. Journal of SPE Reservoir Engineering 1988;3(1): M.K Emera, HK Sarma. A Genetic Algorithm-Based Model to Predict CO 2 -Oil Physical Properties for Dead and Live Oil. Canadian International Petroleum Conference Calgary Alberta User's Guide WinProp; Phase Property Program. CMG software manual Page