Polymer flooding is a well-established chemical EOR technology that is used to overcome challenges associated with conventional waterflooding including viscous fingering and early breakthrough. Nevertheless, polymers tend to perform poorly under harsh reservoir conditions of high temperature and high salinity (HTHS). The main objective of this study is to evaluate and compare the performance of two potential polymers, an ATBS-based polymer and a biopolymer (Scleroglucan), in carbonates under harsh reservoir conditions. This comparative study includes an analysis of polymer rheological experiments as well as polymer injectivity tests. The effects of water salinity and temperature on the performance of these two polymers was also investigated in this study. Rheological experiments were carried out on polymer samples at both ambient (25 °C) and high temperature conditions (90 °C). Polymer viscosity was measured as function of concentration, temperature, and salinity at different shear rates ranging from 1 to 1000 s−1. Injectivity characteristics of both polymers were also assessed through coreflooding experiments using high permeability carbonate outcrops at room (25 °C) and high (90 °C) temperature conditions. The injectivity tests included two stages of brine pre-flush and polymer injection, which allowed assessing the resistance factor (RF) of these polymers. These tests were conducted using high salinity formation water (167,114 ppm TDS) at both temperature conditions. The bulk rheological tests showed that both ATBS-based and Scleroglucan polymers exhibit a shear-thinning behavior. However, the shear-thinning effect is far more evident at higher concentrations in the case of Scleroglucan as opposed to that of the ATBS-based polymer. Viscosity measurements of the polymer samples at different salinities demonstrated the detrimental impact of salinity and divalent ions on the stability of ATBS-based whereas Scleroglucan was not much affected. Scleroglucan exhibited better filterability at the high temperature as opposed to the room temperature. From the injectivity tests, the shear-thinning behavior of the biopolymer in the porous media was confirmed as RF decreased with increasing the flow rate applied at both temperature conditions. Meanwhile, the ATBS-based polymer exhibited a shear-thickening behavior at 25 °C, but a shear-thinning one at 90 °C. Compared to the biopolymer, the ATBS-based polymer showed better injectivity at both the room and the high temperatures as the differential pressure stabilized within the first few pore volumes injected. This study highlights the importance of polymer screening for EOR applications in carbonate reservoirs under HTHS conditions.
Application of polymer flooding in carbonate reservoirs still faces significant challenges, including polymer degradation, injectivity, and retention. With the increased awareness of the importance of water chemistry, this paper investigates the effect of make-up water composition on an ATBS (Acrylamido-Tertiary-Butyl Sulfonate)-based polymer performance focusing on polymer-rock interactions. Comprehensive rheological studies at ambient (25 °C) and reservoir (90 °C) temperatures were conducted on the potential ATBS-based polymer to study the effect of water chemistry. Different make-up water recipes were used with salinity ranging from 400 to 167,000 ppm. Further, static and dynamic adsorption studies were conducted at ambient temperature (25 °C) to investigate polymer performance and polymer-rock interactions. The water recipes with salinity less than 10,000 ppm showed better performance in terms of viscosity enhancement and reduced polymer adsorption. By reducing the overall salinity of the make-up water, the required polymer concentration to achieve a specific target polymer viscosity was decreased by 50-70%. The polymer solution in the diluted brine showed lowered adsorption value of 25 μg/g-rock as opposed to the high salinity formation water (167,000 ppm) and seawater (43,000 ppm) with adsorption levels between 47-56 μg/g-rock. Moreover, a reduction in polymer adsorption was further observed in the presence of crude oil. This research highlights the importance of make-up water salinity on polymer performance and concludes that low salinity water injection enhances polymer flooding performance and reduces polymer adsorption.
Polymer retention is considered as a major challenge in polymer flooding application, especially in carbonates, due to the prevailing harsh conditions of low permeability (< 100 mD), high temperature (> 85 °C), and high salinity (>100,000 ppm). One of the many advantages of smart water technology is maintaining the viscosity of polymers for water-based Enhanced Oil Recovery (EOR) techniques. This research focuses on the effect of water softening on the performance and adsorption of an ATBS-based polymer in carbonate reservoirs. Four different brine recipes were investigated with the salinity of 8,000 ppm TDS and varying ionic composition designed mainly by eliminating the hardness-causing ions, including Ca2+ and Mg2+. A geochemical study was performed using the PHREEQC software to analyze the interaction between these injected brines and the rock. Further, comprehensive rheological and static adsorption studies were performed at a temperature of 25 °C using the potential ATBS-based polymer to evaluate the polymer performance and adsorption with different brine recipes. Later, dynamic adsorption studies were conducted in both single-phase and two-phase conditions to further quantify polymer adsorption. The geochemical study showed an anhydrite saturation index of less than 0.5 for all the brine recipes used when interacting with the rock, indicating a very low tendency for calcium sulfate precipitation. Further, the rheological studies showed that polymer viscosity significantly increased with reduced hardness, where a polymer solution viscosity of 7.5 cP was obtained in zero hardness brine, nearly 1.5 times higher than the polymer viscosity of the base make-up brine of 8,000 ppm. Moreover, it was observed that by carefully tuning the concentrations of the divalent cations, the polymer concentration consumption for the required target viscosity was reduced by 40-50%. For the single-phase static adsorption experiments, the polymer solution in softened brine recipes resulted in lower adsorption in the range of 37 – 62 μg/g-rock as opposed to 102 μg/g-rock for the base make-up brine. On the other hand, the single-phase dynamic adsorption results showed an even lowered polymer adsorption of 37 μg/g-rock for the softened brine recipe compared to 45 μg/g-rock for the base make-up brine. Additionally, the single-phase dynamic adsorption studies showed a remarkable improvement in polymer injectivity using softened brine. The polymer retention in wettability restored cores was further reduced. This study highlights the effect of water softening on polymer performance, particularly polymer adsorption. The paper shows that the softened water increases the polymer viscosity and reduces polymer adsorption, which leads to the overall reduction in polymer consumption. Hence, the softened make-up water has the potential to improve the economics of polymer flood, especially in the case of carbonate reservoirs.
Polymer retention is one of the controlling aspects of an effective polymer flooding process. Very few studies discussed the effect of rock wettability on polymer retention, with no consensus on the outcome. While some studies described that oil-wet rocks have low polymer retention, others reported the opposite. This work investigates the effect of rock wettability on the retention of an ATBS-based polymer onto carbonates at high salinity and moderate temperature conditions. In this study, static and dynamic retention tests of an ATBS-based polymer onto high permeable Indiana limestone outcrops were conducted in both absence and presence of oil. These tests were conducted at 50 °C using representative crude oil and formation water (167,114 ppm) of Middle East carbonate reservoir conditions. For the two-phase dynamic tests, the cores were aged at 90 °C for different times (8 hours, 3 and 14 days) to create different wettability conditions, which were verified by Amott index to water. Then, polymer retention and in-situ rheology, including RF and RRF, were determined. Similar procedure was followed for dynamic single-phase tests, but without core aging. Furthermore, single- and two-phase static tests were conducted under identical experimental conditions to compare the retention values. The results of Amott index to water showed that the selected aging times were suitable for creating different wettability conditions, where cores with longer aging times had a wettability more towards oil-wetting state. It was observed that three-days period of aging was enough to restore the wettability of Indiana limestone outcrops used in this study. Also, polymer dynamic retention was found lower in the presence of oil by about 35 to 47% as opposed to its absence. A further decrease in polymer retention by 14% was obtained for cores with a more oil-wetting condition resulting in a retention level of about 25 µg/g-rock. This is because oil-wet cores have a larger and effective surface area covered by the oil film, leading to a lower surface area left for polymer adsorption as opposed to cores with a wettability towards a more water-wetting state. On the other hand, single- and two-phase static adsorption tests showed non-comparable and very high retention values in the range of 305-337 µg/g-rock. This finding indicates that aging of the rock in such tests does not play a decisive role in obtaining representative polymer retention levels comparable to the dynamic tests. This study is one of the very few works that discuss the effect of rock wettability on polymer retention in carbonates. The study provides an essential insight into the inconclusive results in the literature by highlighting the role of wettability effect on polymer retention based on both static and dynamic retention tests.
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