Gel treatments have been widely applied to control water production in oil and gas reservoirs. However, for water shutoff in dense gas reservoirs, most gel-based treatments focus on individual wells rather than the entire reservoir, exhibiting limited treatment depth, poor durability, and inadequate repeatability Notably, formation damage is a primary consideration in treatment design—most dense gas reservoirs have a permeability of less than 1 mD, making them highly susceptible to damage by formation water, let alone viscous polymer gels. Constrained by well completion methods, gelant can only be bullheaded into deep gas wells in most scenarios. Due to the poor gas/water selective plugging capability of conventional gels, the injected gelant tends to enter both gas and water zones, simultaneously plugging fluid flow in both. Although several techniques have been developed to re-establish gas flow paths post-treatment, treating gas-producing zones remains risky when no effective barrier exists between water and gas strata. Additionally, most water/gas selective plugging materials lack sufficient thermal stability under high-temperature and high-salinity (HTHS) gas reservoir conditions, and their injectivity and field feasibility still require further optimization. To address these challenges, treatment design should be optimized using non-selective gel materials, shifting the focus from directly preventing formation water invasion into individual wells to mitigating or slowing water invasion across the entire gas reservoir. This approach can be achieved by placing large-volume gels along major water flow paths via fully watered-out wells located at structurally lower positions. Furthermore, the drainage capacity of these wells can be preserved by displacing the gel slug to the far-wellbore region, thereby dissipating water-driven energy. This study evaluates the viability of placing gels in fully watered-out wells at structurally lower positions in an edge-water drive gas reservoir to slow water invasion into structurally higher production wells interconnected via numerous microfractures and high-permeability streaks. The gel system primarily comprises polyethyleneimine (PEI), a terpolymer, and nanofibers. Key properties of the gel system are as follows: Static gelation time: 6 h; Elastic modulus of fully crosslinked gel: 8.6 Pa; Thermal stability: Stable in formation water at 130 °C for over 3 months; Injectivity: Easily placed in a 219 mD rock matrix with an injection pressure gradient of 0.8 MPa/m at an injection rate of 1 mL/min; and Plugging performance: Excellent sealing effect on microfractures, with a water breakthrough pressure gradient of 2.25 MPa/m in 0.1 mm fractures. During field implementation, cyclic gelant injections combined with over-displacement techniques were employed to push the gel slug deep into the reservoir while maintaining well drainage capacity. The total volumes of injected fluid and gelant were 2865 m³ and 1400 m³, respectively. Production data and tracer test results from adjacent wells confirmed that the water invasion rate was successfully reduced from 59 m/d to 35 m/d. The pilot test results validate that placing gels in fully watered-out wells at structurally lower positions is a viable strategy to protect the production of gas wells at structurally higher positions.

Excessive water production remains one of the most intractable challenges threatening the economic and sustainable development of oil production worldwide. In situ crosslinking polymer gel systems have been widely adopted as cost-effective chemical solutions for water shutoff and conformance control in oilfields. However, the excessively fast gelation kinetics of conventional gel systems at elevated temperatures severely hinders their application in deep, high-temperature reservoirs. To address this gap, this work systematically evaluates a novel Cobalt(II) (Co(II))-crosslinked polymer gel system developed for water control in high-temperature reservoirs. The effects of polymer type, Co(II) concentration, salinity, temperature, and pH on the gelation time, sol–gel transition behavior, and long-term thermal stability of the system were comprehensively investigated. Compared with the most widely used Cr(III)-crosslinked polymer gel systems, the Co(II)-based gel system exhibits a significantly prolonged gelation time at 130 °C, and the gelation time is positively correlated with the molar content of 2-acrylamido-2-methyl propane sulfonate (AMPS) in the polymer backbone. For instance, the gelation time at 130 °C can be remarkably delayed to 16 days when using the AMPS-rich polymer SAV-10. A unique and distinguishing feature of this polymer/Co(II) gel system is its fully reversible thermoresponsive sol–gel transition behavior. Unlike Cr(III)- and Zr(IV)-crosslinked gels, which form permanent and irreversible gels once crosslinked, the Co(II)-based gel system can crosslink into a robust bulk gel at high temperatures and reversibly switch back to a low-viscosity polymer solution when the temperature drops. For example, the SAV-28/Co(II) mixture forms a stable gel at 130 °C and fully reverts to a flowing polymer solution when the temperature is reduced to 80–85 °C. Furthermore, the SAV-10/Co(II) gel exhibits exceptional long-term thermal stability at 130 °C in both 5% NaCl brine and reservoir formation water, with no observable gel volume loss or syneresis after 100 days of high-temperature aging. The combination of tunable delayed gelation, unique thermoreversible sol–gel transition, and excellent high-temperature stability makes this Co(II)-based gel system a promising candidate for water control in oil and geothermal reservoirs, particularly for targeted plugging in the far-wellbore region and other advanced applications requiring dynamic and reversible fluid diversion.