Polymer flooding is one of the most mature enhanced oil recovery (EOR) methods with many field implementations including those in China, Germany, Oman, and USA. The primary role of polymer is increasing the injected water viscosity, hence reducing the displacing front mobility and thereby improving the macroscopic sweep efficiency. Polyacrylamide, the main polymer used in EOR applications, achieve this increase in viscosity due to the large molecular size of its chains as well as the ionic repulsion between the chains. Those same properties result in significant interactions between the transported polymer molecules and the porous medium, including adsorption, mechanical entrapment, and hydrodynamic retention. Those phenomena, in turn, can lead to polymer losses, injectivity reductions and inaccessible pore volumes. Despite the maturity of polymer flooding, few implementations and research studies have targeted carbonates. Thus, a clear understanding of the magnitude and significance of those interactions and effects for carbonates is lacking. Those phenomena are critical for both numerical predictions and actual performances of polymer flood. Therefore, in this work we investigate thoroughly polymer losses, injectivity reductions and inaccessible pore volumes for a slightly viscous Arabian carbonate reservoir that exhibits high salinity and high temperature conditions. For this purpose, we perform single phase displacement experiments at reservoir conditions. Representative materials were used including simulated brines reflecting connate and injection brine salinities, dead crude oil, and aged reservoir plugs. Core plugs with a wide permeability range from 45.2 md to 12836 md were used for the tests. A pre-screened polyacrylamide was used at an injection concentration of 5,500 ppm. A 2,000 ppm tracer was added into the polymer solution to assess polymer interactions. The effluent polymer concentrations were determined by total organic carbon (TOC) method, and tracer concentrations were analyzed by gas chromatography (GC). Results showed that resistance factor (RF) tended to be higher for tighter samples. RF increased with increasing injection rate for lower permeability samples and decreased with increasing injection rate for higher permeability samples. Residual resistance factor (RRF) slightly decreased with increasing injection rate. RRF correlated well with pore size, with larger pore size corresponding to lower RRF. The effective in-situ viscosity of the polymer was constant at lower injection rates. However, at higher rates, the effective in-situ viscosity increased with injection, exhibiting a shear thickening behavior. Moreover, the polymer exhibited dynamic retention ranging from 0.155 to 0.530 mg/g-rock, and showed a decreasing trend for more permeable core sample. Finally, the studied carbonate constituted of 15.2% to 20.9% pore-volume that was inaccessible to the polymer. Those results besides being essential for numerical-based upscaling of polymer flooding, shed light on some of the similarities and differences between sandstones and carbonates when it comes to chemical EOR application.

Polymer flooding has been recognized as an effective technology to improve oil recovery. While synthetic polymers have been widely used in this process, mechanical degradation tends to occur at near-wellbore regions where flow rate is high. In this paper, we evaluated the polymer mechanical degradation in both core samples and capillary tubes. Results showed that the degradation tended to be severer when the polymer solution flowing through tighter core samples or through capillary tubes with smaller diameter. After mechanical degradation, the polymer average molecular weight was lower and its distribution became wider, indicating the irreversible fragmentation of polymer molecules. The critical shear rate, beyond which evident polymer degradation occurred, tended to be lower for sandstone cores than that for carbonate cores in the same permeability range. On the other hand, the critical shear rates obtained from capillary tubes were significantly higher than those from the core samples. Correlations between the polymer degradation in core samples and in capillary tubes were established, which can be used to estimate the polymer mechanical degradation in reservoir rocks from the more convenient measurement using capillary tubes. This study provides a robust technique for polymer evaluation, and the results are also helpful for better understanding of the polymer flow in porous media.

Polymer mechanical degradation can be induced by high flow rate during the injection in subterranean formations, especially near-wellbore regions. This work presents a study on the polymer injection in carbonate core plugs and capillary tubes at different injection rates in order to assess the critical shear rates beyond which significant polymer degradation takes place. The polymer degradation process in capillary tubes is correlated with that in the carbonate core plugs, which facilitates the degradation assessment. A semi-dilute polymer solution in synthetic injection water was injected into carbonate and sandstone core plugs with different permeabilities and length. The collected effluent solutions were monitored by viscosity measurement using a rheometer and molecular weight distribution measurement using gel permeation chromatography (GPC). Similar procedures were followed for the polymer mechanical degradation using capillary tubes with inner diameters of 0.12, 0.254 and 0.508 mm. Flow in porous media induced severe polymer degradation at a flow rate above the critical shear rate. The carbonate cores showed lower critical shear rates than the sandstone cores. For carbonate core plugs with permeability 390md and 60md, the critical flow rate was 20mL/min corresponding to a shear rate of 4402.1 s-1 and 2mL/min corresponding to a shear rate of 1122.2 s-1. For the sandstone core plugs with permeability 490md and 40md, the critical flow rate was 10mL/min corresponding to a shear rate of 2198.0 s-1 and 1mL/min corresponding to a shear rate of 771.5 s-1. It was observed that greater polymer degradation appeared in the flow through the lower permeability core plugs. Core length had limited effect on the degradation. The average molecular weight became smaller while the molecular weight distribution became wider for the polymer solutions after the mechanical degradation, indicating the irreversible fragmentation of polymer molecules. In comparison, polymer degradation in capillary tubes appeared at a critical shear rate in the magnitude of 200,000 s-1. Similar with the scenarios of polymer injection in core plugs, greater viscosity loss happens in the flow through smaller capillary diameter. By the correlation, the polymer degradation in carbonate core plugs can be predicted by the measurement in the capillary tubes. This work provides the insight of polymer mechanical degradation in carbonate matrix. An easy-to-operate method on the evaluation of polymer mechanical degradation was developed to assist in the operation of the polymer injections.

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