A new solid-free high-density colloidal particle temporary plugging fluid for high-temperature gas well completion

The reservoir damage caused by wellbore fluid loss – such as permeability reduction and water lock – hinders effective EOR implementation and leads to reservoir contamination. This issue is especially critical in high-temperature and high-pressure (HTHP) reservoirs, where conventional colloidal temporary plugging fluids often fail due to low density, poor thermal stability, and severe salting-out–induced damage. In this work, we develop a solid-free, zwitterion-modified carboxymethyl cellulose (CMC) colloidal particle system (CAA) that addresses these limitations. The system combines formate-assisted density enhancement (maximum density of 1.55 g/cm³) with a thermally stable, salt-shielded polymeric network. Unlike previously reported starch- or PAM-based systems, which are limited to temperatures below 140 °C and densities ≤1.3 g/cm³, the CAA system remains stable at 160 °C, pressures above 25 MPa, and under high-salinity conditions. Microstructural evidence further confirms swelling-induced pore filling. Pressure-bearing and flowback experiments demonstrate that the CAA system withstands reservoir pressures exceeding 25 MPa and achieves core permeability recovery of up to 92.1%, outperforming previously reported colloidal plugging systems. This study presents a new design strategy for solid-free, high-density plugging fluids and provides both mechanistic insights and experimental validation. The results support their effective application in extreme HPHT well operations, improving reservoir protection and enabling safer field implementation.