I would like to take this opportunity to thank all my fellow group members and all professors and employees of the Department of Petroleum Engineering of Nazarbayev University for creating a fertile atmosphere for development. One of the most commonly applied techniques for Chemical Enhanced Oil Recovery (CEOR) is polymer flooding, which uses polymer solutions to increase the viscosity of the displacing water and improve mobility control and sweeping efficiency. The Uzen field is one of the largest and oldest oil fields in the entire country and an increase in oil production could be crucial to meet growing energy demand.
This work is focused on the laboratory evaluation of the performance of three synthetic polymers under Uzen field conditions. In conclusion, polymer flooding with Sav 10 polymer under Uzen field conditions was an effective EOR technique and can be recommended for implementation. 19 Figure 3 - Dynamics of the main technological production indicators of oil-bearing horizons in the Uzen field for 2009 - 1st half of 2014.
36 Figure 20 - Effect of increasing temperature on the viscosity of 6000 ppm polymer solution with different weight percentages of two polymers SAV37 and AN125VHM (Salinity of 10000 ppm). 37 Figure 21 - The effect of increasing salinity on the viscosity of 6000 ppm polymer solution with different weight percentages of the two polymers SAV37 and AN125VHM (Room temperature).
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Introduction
- Background
- Problem definition
- Thesis objectives
- Significance of work
Polymer flooding is one of the most widely used CEOR methods and tertiary oil recovery techniques in general (Sheng, 2014). Field implementation data for polymer flooding, presented in several studies, confirms the effectiveness of polymer flooding over conventional water flooding. Namely, the efficiency of polymer flooding decreases dramatically in reservoirs with high temperature and salinity (Yanbiao and Jiangbo, 2005).
In general, the use of polymer flooding in high salinity reservoirs (more than 85000 ppm) has an impact on oil recovery similar to that of water flooding (Algharaib, 2014). Most polymer flood field designs have been designed for use in sandstone reservoirs (Sheng, 2011). Thermal degradation causes a loss of polymer viscosity due to exposure of solutions to elevated temperatures.
However, a successful application of polymer flux in the specific field requires a well-designed evaluation and selection process, based on the analysis of field data. The main objective of this thesis work is to design and conduct a proper set of laboratory experiments to select a suitable polymer candidate for the application of polymer flux in the Uzen field.
Literature review
- The Uzen field characteristics
- Reservoir screening criteria for the application of polymer flooding
- Polymer Stability
- Mechanical stability
- Chemical stability
- Thermal stability
- Zetag 8187G (Firozjaii et al., 2019)
- The bulk scale investigation of 9 synthetic ATBS and NVP containing polymers
- Comparative analysis of polymer flooding using polysaccharides and a synthetic polymer under harsh conditions (Liang et al., 2019)
Combining all the above data, we can assume that the use of polymer irrigation as a tertiary recovery technique will be effective in the Uzen field for several reasons. Second, polymer flooding reduces viscous ringing in highly permeable zones by reducing the mobility ratio of the displaced fluid (Sheng, 2011). Therefore, the implementation of polymer as tertiary processing could be used at the next stage of field development.
As a result, the combination of the field data from the previous section and Table 6 shows that polymer flooding can be used in the Uzen field. Some of the projects recorded a viscosity loss of polymer solution on surface conditions due to mechanical degradation. Therefore, the manner in which the polymer solution is transported to the wellhead is a critical factor in polymer stability.
Based on research by Yang and Taber (1985), there are many variables that can affect the chemical stability of polymer solution. At the low oxygen concentration, the viscosity of the polymer solution decreased slightly compared to gradual decrease in the presence of significant oxygen concentration. Increased hydrolysis reduced amount of polymer solution, which is adsorbed by surface of media, leading to increased viscosity of the solution.
After one week, the viscosity of the polymer solution at a temperature of 90 °C and a salt ion concentration of 2.85% total dissolved solids (TDS) was higher than that of the polymer at 23 °C and the same salinity. This is due to an increase in polymer molecules and a decrease in friction between molecules, which causes a loss of viscosity. In this work, the authors studied the performance of a polymer solution containing two synthetic polymers SAV37 and AN125VHM.
Источник ссылки не найден.22 represents viscosity loss of polymer solutions due to temperature increase at a constant salinity of 150,000 ppm. The investigated polymer solution performed adequately under conditions more hostile than those of the Uzen field. Significantly, the increase in salinity affected the performance of the same polymers by decreasing their viscosity.
Flopaam™ AN110VHM was replaced by Sav226 terpolymer containing NVP in the higher salinity test to evaluate the effect of the NVP group on polymer stability. One of the most important tests for the application of polymer flooding is the long-term thermal stability.
Methodology
- Materials
- Formation water
- Oil sample
- Polymers
- Experimental methods and procedure
- Brine and polymer solutions preparation procedure
- Long-term thermal stability tests
- Mechanical degradation
- Core preparation
- Injectivity tests
- Oil Displacement test
Oil, which was used as a reference fluid in nuclear flooding experiments, was arrived from Kenkiyak-Kumkol field. Unfortunately, the use of oil from the Uzen field was not possible due to the inaccessibility of samples at the time of the experiments. Nevertheless, the viscosity of the oil samples, which are in this use, works 1.5 to 2 cp lower than the real one in the conditions of Uzen field.
The composition of the 16th horizon of the Uzen field was used to prepare the polymer solution as component water and injection water in the nuclear flooding experiments. After the 77000 ppm brine solution is ready, polymer solutions were prepared according to API standards (API RP 63). The brine solution of the compound with the required volume in a beaker was placed in a magnetic stirrer to create a vortex, which occupied 70% of the volume of water.
106 (1) Then a polymer powder was slowly sprinkled on the shoulder of the vortex for 30 seconds to prevent the formation of large amounts of polymer powder. It is crucial to know the behavior of polymer rheology at different temperatures as it may vary in different parts of the reservoir. In all cases, the salinity of the Uzen formation water was used for the preparation of polymer solutions.
The evaluation of the polymer viscosity at room temperature was performed using a cone plate measurement system (see Figure 42). After a certain time, test tubes were removed from the oven for viscosity measurement. The mechanical stability of the chosen polymer solutions was evaluated using Hamilton Beach Single Spindle Drink Mixer HMD 200 (Figure 44).
Three polymer solutions with a polymer concentration of 2500 ppm were exposed to a high shear rate of 400 s-1 for different time intervals. Determination of the displacement efficiency in terms of recovery factor is a mandatory stage of polymer screening. Brine and polymer solutions for oil recovery were injected at a rate of 5 cc/min.
Results
- Bulk scale rheological investigation
- The effect of concentration
- The effect of temperature
- Mechanical stability
- Long-term thermal stability test
- Injectivity tests
- Oil displacement test
Compared to Sav 10 XV, these polymers showed a less significant decrease in viscosity with an increase in shear rate at all concentrations. However, the Sav 10 XV typically showed a small Newtonian fluid region at the higher shear rates as shown in Figure 50. Moreover, Sav 10 XV showed more shear sensitive behavior with a dramatic viscosity loss compared to other two polymers in all cases.
In addition, Newtonian fluid behavior of Sav 10 XV solution was observed at the higher shear rates. It is clear that 2500 ppm Sav 10 solution has the worst thermal stability with approximately 60 % viscosity loss at 80 ̊C. Furthermore, Sav 10 XV had a viscosity degradation factor of approximately 23 % percent at the end of the experiment.
This can be explained by a lower shear sensitivity of Sav 10 compared to the other two candidates. As a result, this different shear behavior of polymers could be a possible reason for increased RF values for Sav 10 XV flooding. It should be noted that the injection rate of 1000 ppm Sav 10 XV flood was not increased to 5 cc/min for safety reasons because the pressure difference was extremely high.
Thus, there is no data on the resistance factor value for 1000 ppm Sav 10 XV at 5 cc/min injection. The highest differential pressure at the same rates was provided by polymer solutions Sav 10 XV. The lowest pressure values were provided by Sav 10 in all concentration groups (minimum, average and maximum).
In addition, Sav 10 polymer showed the best mechanical stability at high shear rates and acceptable long-term thermal stability. Overall, Sav 10 injection was effective and increased total oil recovery by nearly 12% even after oil displacement with 9 PV brine injection at the highest injection rate (5 cc/min). In conclusion, the use of Sav 10 flooding improved the cumulative oil recovery and can be recommended for sector simulation.
Conclusions and Recommendations
To create the simulation of the polymer flood sector with Sav 10 solution under Uzen field reservoir conditions to evaluate its performance on a larger scale.
Pore-scale investigation of viscoelastic phenomenon during enhanced oil recovery (EOR) polymer flooding through porous media. Polymer flood pilot case study in a low permeability Mannville sand of the western Canadian sedimentary basin using produced water for mixing. Comparative Study of Enhanced Oil Recovery under High Temperature and High Salinity: Polysaccharides versus Synthetic Polymer.
Press the casing for polymer flooding to high-temperature and high-salinity reservoirs with polyacrylamide-based ter-polymers. Study of the mechanism of polymer dissolution with viscoelastic behavior that increases microscopic oil displacement efficiency and the formation of steady "Oil thread" flow channels. Synthesis and study of a new copolymer for polymer flooding in high-temperature, high-salinity reservoirs.
Experimental investigation of key effect factors and oil displacement efficiency simulation for a new modified polymer BD-HMHEC.
