High-molecular-weight partially hydrolyzed and sulfonated polyacrylamides are widely used in enhanced oil recovery (EOR). Nonionic polyacrylamide and polyacrylamide-based microgels are also used in water shut-off treatments for gas and oil wells. A comparative study of the mechanical degradation for three linear polyacrylamides and a microgel is presented. Mechanical degradation is quantified from the loss of the viscosity of the polymer solution as it passes through a stainless steel capillary with a length of 10 cm and an internal diameter of 125 mm. The critical shear rate above which degradation increases exponentially was found to depend on the chemical structure of the polymer, molecular weight, and electrolyte strength. The nonionic polyacrylamide shows higher degradation and lower critical shear rate compared with a sulfonated polyacrylamide with similar molecular weight. Moreover, the nonionic polyacrylamide with a higher molecular weight results in lower mechanical degradation. The higher mechanical stability of the sulfonated polymer is attributed to the higher rigidity of its molecules in solution. On the other hand, the ability of the highmolecular-weight polymers to form transient, flow-induced microgels boost their mechanical stability. This ability increases with the increase in the molecular weight of the polymer. Indeed, the microgel solution used in this study demonstrates exceptional mechanical stability. In general, mechanical stability of linear polymers used in chemical enhanced oil recovery can be enhanced by tailoring a polymer that has large side groups similar to the sulfonated polyacrylamide. Also, polyacrylamide-based microgels can be applied if high mechanical stability is required.

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Treated oilfield produced water is injected into reservoirs to increase the depleted reservoir pressure and enhance oil recovery. The main challenges in this process are injectivity decline and high tubing head pressure (THP) which is most often caused by the deterioration in the reservoir permeability. This investigation focuses on identifying root causes behind injectivity decline in a sandstone reservoir in Oman. Acid stimulation has been applied to improve the reservoir permeability, but it turned out to be non-feasible due to frequency of such interventions and high associated costs. Several factors, such as injection water quality and reservoir mineralogy, can adversely affect the reservoir permeability and cause injectivity decline. Various approaches to tackle this problem have been adopted in this study including; water analysis, scale modeling, formation damage simulation and core flooding experiments. The scale modeling results showed compatibility between formation and injection water where the scaling potential for both barium sulphate (BaSO4) and calcium carbonate (CaCO3) scales were unlikely to form at reservoir conditions. Injection water analysis showed that, in some cases total suspended solids and oil content exceeded the recommended limit, which might contribute to reservoir permeability decline. XRD analysis of the reservoir core samples revealed that fines and expansive clays are the main components. The core flooding experiments demonstrated that reservoir pore throats get plugged due to two main factors; the suspended solid particles present in the injected water and swelling clays present in reservoir core samples. The formation damage simulator showed that fines migration and clay swelling are the two main possible formation damage mechanisms. To enhance the water injectivity process, the use of a clay swelling inhibitor along with a filtration system to remove suspended particles in the injected water are recommended for the reservoir studied.