Research on Gel Water Plugging Agent and Parameter Optimization for Fractured-Porous Bottom Water Reservoirs

In response to the critical water production issues encountered in fractured-porous bottom-water gas reservoirs during the middle-to-late development phase, a gel-based water shutoff agent with superior salt tolerance and long-term stability was developed through systematic optimization of primary agents, crosslinkers, and stabilizers. Comprehensive performance evaluations of the gel system were conducted to validate its applicability in complex reservoir environments. Formulation Optimization and Composition The gel water shutoff agent was engineered with a three-component system: Primary Agent: The salt-tolerant hydro-phobic associating polymer SA-5 was selected as the backbone component, applied at a concentration range of 2500–3000 mg/L to ensure structural integrity in high-salinity formation water. Crosslinker: An organic chromium-based cross-linker was incorporated at 6000–10,000 mg/L, enabling the formation of stable three-dimensional networks through coordination reactions with polymer chains. Stabilizer: The organic diamine additive was included at 100–200 mg/L to enhance thermal-chemical stability and retard gel degradation over extended periods. Gel Performance Characterization Under reservoir conditions (75 ℃), the gel sys-tem exhibited the following key properties: Gelling Kinetics: A primary agent concentration of 3000 mg/L yielded a controllable gelling time of 20–30 h, followed by the development of a robust gel structure reaching Grade G strength (as per API RP 39 standards). Long-Term Stability: The gel maintained structural integrity for over 120 days, demonstrating resistance to thermal aging and salinity fluctuations. Plugging Efficiency: Injection of 1.0 PV of the gel into artificial fractured cores achieved a 98.2%+ plugging efficiency against dominant seepage pathways, effectively mitigating water breakthrough. Profile Modification: The system demonstrated exceptional reservoir profile improvement, with a measured 87.04% profile modification efficiency, indicative of balanced fluid distribution across different permeability zones. Field Application Parameters Optimization Leveraging reservoir data from the TX gas field, a numerical simulation model was constructed using CMG software to optimize operational parameters for gel injection: Concentration: The optimal working concentration was validated as 2500–3000 mg/L, balancing gel strength and cost-effectiveness. Injection Volume: A target volume of 0.6 PV was identified to achieve complete coverage of high-permeability channels while minimizing waste. Injection Rate: A controlled rate of 0.15 PV/d was recommended to prevent matrix invasion and ensure uniform placement within fractured networks. Engineering Significance. This study provides a technically robust solution for enhancing recovery in high-water-cut gas wells of fractured-porous bottom-water reservoirs. The developed gel system and optimization framework offer: Direct technical support for water control operations in similar geological settings; A transferable methodology for chemical profile modification in carbonate and clastic gas reservoirs worldwide. The findings highlight the potential of polymer-based gel systems as a sustainable strategy for managing water production challenges in mature gas fields, combining reservoir protection with economic viability.