Controlling unwanted water production is the key for the oil and gas industry. Consequently, water shutoff (WSO) fluids were introduced to favorably plug high permeability water zones or fractures and thereby reducing the water cut. Polymer gels have been utilized extensively to minimize undesired water production, especially from oil producers. Herein we present the study of gelation kinetics of an organically crosslinked polymer (OCP) gel with an adsorption system from intermediate to high reservoir temperatures. In this study, we utilized a cost-effective and environmentally acceptable fluid system. The fluid consists of polymer gel and adsorption constituents for carbonate formations. The system can be pumped downhole to the targeted zones as a single-phase solution with low initial viscosity. A systematic evaluation of the polymer gel for WSO applications is conducted at varied reservoir conditions. This includes a thorough examination of fluid properties at surface conditions before gelation starts, at which the system is referred to as gellant. Furthermore, we studied the properties during and after gelation kicks off at a wide range of temperatures. The emphasis of the experimental investigation was on the kinetics of OCP gelation through performing several rheology experiments at various crosslinker concentrations. The analysis revealed that the viscosity of the gellant at standard conditions was less than 20 cP; thereby, this contributes positively to having smooth surface mixing and pumping requirements for field testing. Based on reservoir temperature and cooling effect, the gelation time can be optimized by altering crosslinker concentrations. At fixed temperatures and varied crosslinker ratios, the gelation time exhibited a linear relationship with crosslinker concentrations. Additionally, the gelation time against temperature experienced an exponential behavior with reversible proportionality. By plotting the acquired data from massive rheological tests, we managed to attain precise correlations of gelation time for each OCP formulation. The gel prevailed in a high thermal stability fluid system to be gelled at a temperature of more than 250°F. Based on the presented lab observations, we concluded that this polymer gel system is expected to be trial tested in the field as WSO fluid for carbonate rocks. The OCP gel is a promising technology to mitigate excess water production from oil producers. Since the system has a low initial viscosity, it can be injected naturally in porous media. The presented work offers an insightful polymer gel system as a WSO fluid designed for treating carbonate rocks.
Carbonate reservoirs hold 60% of the world's oil and 40% of the gas. Therefore, developing high-impact and innovative technologies for well stimulation, such as foamed acid fracturing fluids, is essential for restoring well productivity and enhancing commercial productivity for carbonate reservoirs. Acid fracturing treatment is associated with reactivity control, fluid loss control, and conductivity generation challenges. For overcoming some drawbacks associated with conventional acid fracturing, foamed acid fluid is applied to enhance retardation, reduce water consumption, improve acid diversion, remove water or emulsion blocks, and improve conductivity generation. In this study, a unique foamed acid system stabilized by composite material was studied to develop fracturing fluid at 275-350 °F. In addition, the foam stability, rheology, and morphology characteristics were investigated using several characterization tools at 275-350 °F. The composite material comprises nanosheet (NS), and surfactant (SURF) were added to either a pure-acid or acid system that contains several additives for developing stable NS/SURF-based foamed acid fluid. To evaluate foam rheological properties and thermal stability at dynamic conditions, foam loop rheometer experiments were conducted at 275-350 °F, 1050 psi, and 70 % N2 quality. A high-resolution optical microscope was also utilized to observe foam texture morphology and further assess foam stability. In addition, foam-decaying time was observed by determining the foam-half-life-time (foam volume altering as a function of time). The static and dynamic results illustrated that foamed acid fluid stability and thermal adaptability were improved after adding composite material at 275-350 °F. The viscosity of foamed acid increased by double and its viscosity was higher than 45 cP at a shear rate of 300 S-1 and 350 °F. In addition, the foam-structure of NS/SURF-based foamed acid displayed a small hexagonal bubbles size, which positively affected the stability of foam to reach up to three hours at 300 °F. In contrast, the stability of pure foamed acid was one hour. This result is attributed to the adsorption of composite material at the liquid-gas interface layer that enhances the mechanical strength of the foam-layer (lamellae film) and provides a more robust barrier between the gas bubbles and liquid phase, resulting in delaying the coalescence of the bubbles. The developed NS/SURF-based foamed acid possesses several advantages over the conventional acid fracturing fluids: long stability, adequate viscosity (obtained without adding gelling agent), low water consumption, and high efficiency at 275-350 °F.
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