Iranian Journal of Oil and Gas Science and Technology

Abstract Excessive water production represents a significant economic and operational burden in the petroleum industry, necessitating sophisticated control measures to mitigate costs associated with water oil separation, scale formation, and equipment corrosion. This investigation characterizes the performance of preformed particle gels (PPG) as a robust chemical water shutoff treatment through comprehensive rheological and swelling kinetics studies. Experimental results demonstrate that PPG viscosity is highly sensitive to concentration; specifically, a twofold increase in concentration (from 2500 to 5500 ppm) results in a tenfold increase in viscosity. The rheological behavior was successfully modeled using the Cross equation, facilitating the derivation of a unified mathematical model that predicts viscosity as a function of concentration and shear rate. Crucially, at a calculated shear rate of 0.14 s⁻¹ based on the assumption that injection velocity is 100 times the reservoir oil movement PPG maintains sufficient viscosity for effective flow diversion. Furthermore, the study explores the influence of agitation and salinity on swelling performance. Stirring was found to accelerate swelling kinetics, shifting the mechanism from Fickian diffusion at zero RPM to a transport dominated mechanism (n ≈ 0.85) due to the simultaneous activation of multiple diffusion pathways. Salinity experiments utilizing KCl and MgCl₂ reveal that divalent cations (Mg²⁺) are significantly more effective at inhibiting swelling than monovalent cations (K⁺) due to charge neutralization of carboxylate groups. Morphological analysis via Scanning Electron Microscopy (SEM) suggests that ions with larger radii obstruct the gel pores, a phenomenon that can be mitigated during synthesis through the introduction of nonionic hydrophilic monomers and pore forming agents such as ethanol or ammonium bicarbonate. Finally, the research identifies diffusion limited aggregation (DLA) as the dominant growth mechanism. Modified DLA models were developed to predict salinity dependent swelling, providing a rigorous framework for optimizing PPG treatments in heterogeneous reservoirs

Abstract Currently available polymers as a component of in-situ gels are unsuitable for treating high-temperature/high-salinity reservoirs due to their chemical and thermal degradation. In this study, a new copolymer-based gel system including high molecular weight nanostructured polymers (NSPs) was developed to address the excessive water production problem in reservoirs under harsh conditions. The stability of conventional polymer systems and NSPs was investigated under conditions of 40 days aging at 87000 ppm salinity and 90 °C. Then, gelation time optimization of gel systems composed of NSPs and chromium (III) acetate was performed with regards to the effect of copolymer concentration and copolymer/cross-linker ratio and their interactions during the gelation time. The central composite approach was used to design experiments and build a mathematical model. The analysis of variance (ANOVA) was used to estimate the deviation of the model predictions from the data. The results of stability analysis demonstrated the advantages of NSPs over conventional polymers by a viscosity reduction of 69, 36, and 18% for Flopaam3310, AN105, and NSPs respectively. The model developed for the prediction of gelation time of NSPs gel was significant at a confidence level of 98.6% against the test data. Moreover, it was found that gelation time became longer with a decrease in copolymer concentrations and/or increase in copolymer/cross-linker ratio.