One of the Kazakh fields where the water content is very high is the Uzen field. Adsorption of the polymer in the porous medium also affects the actual concentration of the polymer during flooding.
The Uzen Field
The decision to do cold water injection was unsuccessful and resulted in a sharp drop in the productivity of the wells (Soroush et al., 2021). The pilot test of polymer flooding has been successfully conducted for more than 10 years through 3 injection and 14 production wells in the field by the KazMunaiGas Engineering service company (Imanbayev et al., 2022a). Nevertheless, to have a clear overview of how polymer flooding can affect the performance of the Uzen field, the application of the polymer flooding in several analog fields should be analyzed and the comparison in the rock and fluid properties with the Uzen field should be performed.
The field is considered to be analogous to the Uzen field in terms of oil wax content and similar reservoir temperature. In the first phase, the performance of polymer flooding was tested in the field by converting 2 of the production wells to polymer injectors. As a result of polymer flooding in the reservoir, the reduction in water cut is between 2-30% and the increase in oil production is about 25% (Singh et al., 2021).
The success of polymer flooding in fields similar to the Uzen field worldwide shows that the implementation of the polymer EOR method should result in similar behavior and increase in oil production and decrease in water cut.
Polymer Screening: Previous Studies on Polymer Performance
The goal was to reach the viscosity of 5 cp at a shear rate of 10 [1/s] under reservoir conditions. The viscosity results are presented in Figure 18 and reveal that a significantly higher concentration of polymer is required for Polymer 1 to reach the target viscosity of 5 cp compared to the other three candidates. Thus, the use of Polymer 1 is not economically advantageous, as a higher concentration of polymer leads to a higher cost for the EOR project.
Based on the results obtained, the correlation between initial viscosity, viscosity degradation and concentration was used to determine the stabilized (final) viscosity of the polymers as a function of polymer concentration as shown in Figure 20. Further, the adsorption test was carried out with using a polymer solution prepared with real Caspian Sea water and mixed with the crushed Upper Bera sandstone core sample. The results of adsorption and retention of the polymer solution in porous media collectively lead to a decrease in the permeability of the displacement phase (Zhu et al., 2021).
From Figures 21 and 22 it can be concluded that polymer 2 has higher adsorption at any given solid to liquid ratio and regardless of polymer concentration.
Problem Statement
33 To summarize, the results of these screening experiments revealed that the most suitable for the Uzen field polymer type with the lowest absorption and thermal degradation values is Polymer 3, while its optimal and economically useful concentration is 2500 ppm. 34 During core flooding tests, polymer is injected into the core sample under reservoir pressure and temperature that are high enough to cause degradation of the polymer molecules. Polymer molecules are very sensitive to any deviation, whether it is an increase in temperature or pressure, mechanical rotation, compression or expansion, the polymer can degrade in any of these factors.
The combination of all degradation factors will dictate how the polymer will behave when injected into the tank. The yield factor is the most important factor to know when it comes to using EOR. The recovery factor indicates how much increase in oil production can be achieved after polymer treatment.
The main objective of this step is to evaluate the recovery limits that can be achieved by injecting the selected polymer at the selected concentration, taking into account all the screening criteria and degradation factors discussed above.
Methodology
Materials 1. Crude Oil
First, the core samplers will be saturated with the given formation water (FW) sample taken from the Uzen field (Figure 25), in order to better match the reservoir condition, taking into account the specific water contamination local. According to the information provided by the provider company, the density of the formation water is 1.1 g/cc. This is done to prevent clogging of the pores in the core sample by foreign particles, which can cause inaccuracies in the results.
The length and diameter of the core were previously measured with a caliper (Figure 29). To calculate the pore volume of the samples, the cores were saturated with formation water using manual saturation (Figure 30). Vigorous agitation is required to effectively disperse the dry powder, and the bottom of the water vortex on a magnet-driven laboratory stirrer must penetrate 75% of the liquid (Figure 32).
Immediately thereafter, the stirrer should be set to a low speed (150 RPM) to prevent solid particles from sinking and also to avoid degradation of the polymer solution.
Procedure
The core sample was saturated with FW and then flooded with FW at different rates to determine the absolute permeability of the core. In the next step, the crude oil was injected into the core at a flow rate of 0.2 cc/min and this was continued until the effluent water fraction was reduced to less than 0.1%. The injection rate was increased to 2.0 cc/min to overcome capillary end effects and achieve initial water saturation (Swi) in the core.
The conditions for changing the flow rate were to have a drop in flow water of less than 0.1% and a stabilized pressure drop across the core sample;. The volume of oil produced during the waterflood was used to calculate the recovery factor using equation 3;. The stabilized pressure drop for water flooding and polymer flooding were also used to calculate the two-phase resistance factor (RF) for comparison purposes.
Finally, a post-rinse of the brine was performed to calculate the residual resistance factor (RRF) in the presence of oil and to displace the adsorbed polymer.
Results and Discussion
Oil Displacement test with Caspian Seawater
The graph reveals that pressure drop values for the pre-rinse stage range between approximately 35 psi and 125 psi, for polymer injection - from 75 psi to 245 psi, and for post-rinse - between 0 psi and 17 psi. The resistance factor (RF) and residual resistance factor (RRF) were also easily estimated from the pressure drop data for each flooding stage to estimate the injectivity of the fluids. RF is expressed as the ratio of the stabilized pressure drop during polymer flooding to the stabilized pressure drop during water flooding (pre-rinse).
The resistivity factor, in turn, is defined as the ratio of stabilized pressure drop during post-flush to the stabilized pressure drop during pre-flush. RRF is expected to be close to 1 if no pore clogging occurred during the polymer injection. The estimated RF and RRF results for Caspian seawater-based polymer flooding are presented in Table 5.
Stabilized pressure drop at each flow rate and corresponding RF and RRF (for Caspian seawater case).
Oil Displacement test with Alb water
According to Figure 39, the pressure drop during pre-rinsing with Alb water varied between approximately 20 psi and 55 psi, during polymer injection - between 125 psi and 255 psi, and reached up to 40 psi during post-rinsing. Meanwhile, oil recovery for waterflooding with Alb water only reached about 31% OOIP and an additional recovery of 29% OOIP by water-based Alb polymer injection. RF and RRF for the water-based Alb polymer case are also estimated for comparison with the seawater case and shown in Table 7.
Stabilized pressure drop at each flow rate and corresponding RF and RRF (for Alb water case). Turning to the rheology of the effluents, the recorded viscosity values are shown in Table 8, as well as the calculated percentage of polymer degradation in relation to the initial viscosity of the polymer.
Discussion
The recovery factor results also prove the fact that the possible oil production by seawater-based polymer, which is approximately 47% OOIP, is higher than the oil production by water-based Alb polymer, which is approximately 29% OOIP. In total, a recovery factor of 91% was obtained with seawater as pre-rinse and seawater-based polymer (Figure 38) and more than 60% with Alb water as pre-rinse and Alb-water-based polymer (Figure 39). . Meanwhile, if we only consider oil recovery from water flooding, seawater as a prewash showed better performance than Alb water.
Despite the former requiring a higher pressure drop, it resulted in a recovery factor of 43% OOIP (Figure 38), while Alb-water produced only 31% OOIP (Figure 39), respectively. This phenomenon can probably be explained by a higher concentration of divalent ions such as 𝐶𝑎2+ and 𝑀𝑔2+ (Table 3), which affect the detachment of oil molecules from the rock surface. The higher the concentration of divalent ions such as 𝐶𝑎2+ and 𝑀𝑔2+, the greater the detachment of oil from the rock surface.
To summarize, based on this difference in recovery factors, it was decided that Caspian sea water as the pre-rinse, followed by injection of the polymer prepared with the sea water, shows greater performance compared to the Alb water case.
Conclusion and Recommendations
Recent advances in the application of nanotechnology in chemical enhanced oil recovery: Effects of nanoparticles on wettability modification, interfacial tension reduction and flooding. An evaluation of the enhanced oil recovery potential of the xanthan gum and Aquagel in a heavy oil reservoir in Trinidad. Shear breakdown model of HPAM solutions for the design of regulator valves in polymer that Eor.
A Critical Review of Daqing Field and Pelican Field Polymer Flooding: Case Studies of the World's Largest Polymer Flooding in Light and Heavy Oil Reservoirs. A Review of Chemically Enhanced Oil Recovery: Recent Advances and Prospects - Nano Letters International, SpringerLink. A Review of Polymer Flooding Performance in the Sultanate of Oman Large Oilfield, SPE Asia Pacific Enhanced Oil Recovery Conference.
Appendix B: Volumes of Oil Produced in Effluents and Calculated Oil Recovery Factor with PV of Injected Fluid.
