Viscosity losses and high degradation factors have a drastic impact over hydrolyzed polyacrylamides (HPAM) currently injected, impacting the oil recovery negatively. Previous studies have demonstrated that biopolymers are promising candidates in EOR applications due to high thermochemical stability in harsh environments. However, the dynamic behavior of a biopolymer as scleroglucan through sandstone under specific conditions for a heavy oil field with low salinity and high temperature has not yet been reported. This work presents the rock–fluid evaluation of the scleroglucan (SG at 935 mgL⁻¹) and sulfonated polyacrylamide (ATBS at 2500 mgL⁻¹) to enhance oil recovery in high-temperature for heavy oils (212 °F and total dissolved solid of 3800 mgL⁻¹) in synthetic (0.5 Darcy) and representative rock samples (from 2 to 5 Darcy) for a study case of a Colombian heavy oilfield. Dynamic evaluation at reservoir conditions presents a scenario with stable injectivity after 53.6 PV with a minimal pressure differential (less than 20 psi), inaccessible porous volume (IPV) of 18%, dynamic adsorption of 49 µg/g, and resistance and residual resistance factors of 6.17 and 2.84, respectively. In addition, higher oil displacement efficiency (up to 10%) was obtained with lower concentration (2.7 times) compared to a sulfonated polyacrylamide polymer.

Biopolymers emerge as promising candidates for enhanced oil recovery (EOR) applications due to their molecular structures, which exhibit better stability than polyacrylamides under harsh conditions. Nonetheless, biopolymers are susceptible to oxidation and biological degradation. Biopolymers reinforced with nanoparticles could be a potential solution to the issue. The nanofluids’ stability and performance depend on the nanoparticles’ properties and the preparation method. The primary objective of this study was to evaluate the effect of the preparation method and the nanoparticle type (SiO₂, Al₂O₃, and TiO₂) on the viscosity and stability of the scleroglucan (SG). The thickening effect of the SG solution was improved by adding all NPs due to the formation of three-dimensional structures between the NPs and the SG chains. The stability test showed that the SG + Al₂O₃ and SG + TiO₂ nanofluids are highly unstable, but the SG + SiO₂ nanofluids are highly stable (regardless of the preparation method). According to the ANOVA results, the preparation method and standing time influence the nanofluid viscosity with a statistical significance of 95%. On the contrary, the heating temperature and NP type are insignificant. Finally, the nanofluid with the best performance was 1000 ppm of SG + 100 ppm of SiO₂_120 NPs prepared by method II.

Polymer flooding represents the most common chemical enhanced oil recovery (CEOR) method used at commercial scale. In this process, the polymeric solutions (generally hydrolyzed polyacrylamide - HPAM) are injected to improve the oil/water mobility ratio (M). However, due to mechanical, chemical, bio, and thermal degradation, polymer viscosity losses can occur, causing a negative impact on oil sweep efficiency. In this case, biopolymers seem to be promising candidates in EOR applications with special structural characteristics, which result in excellent stability in harsh environments with high temperatures, ionic forces, and shear stresses. This paper presents the laboratory evaluation of Scleroglucan (SG) and a commercial sulfonated polyacrylamide (ATBS) in synthetic brine, representative of a Colombian heavy-oil field. The effects of ionic strength, pH, temperature, and shear degradation effects on polymer viscosity were also evaluated. For SG, the results reflect its tolerance to high salinities (0-5%wt), ionic strengths (Na+, K+, Ca2+, and Mg2+), shear rates (0-300,000 s-1), temperatures (30, 50, 80 and 100 °C), and pH variations (3-10). The biopolymer was capable of preserving its viscous properties and stability after of the effect of these variables. Finally, the target viscosity (set as 17 cp) was achieved with a lower concentration (2.7 times) than the ATBS polymer tested.

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.