Low-density workover fluid technology designed to lower the required sealing strength for operations in the fractured reservoirs of the Ordos Basin

Abstract The tight Upper Paleozoic sandstone reservoirs and Lower Paleozoic carbonate reservoirs in the Ordos Basin necessitate fracturing or acidizing to generate artificial fractures prior to production, classifying them as typical fractured reservoirs. During workover operations, the depletion of formation pressure results in a considerable loss pressure differential. Conventional sealing operations impose overly stringent requirements on plugging materials, giving rise to substantial risks of formation damage and slow post-workover production recovery rates. Laboratory investigations identified optimized components: modified lauramidopropyl betaine as the foaming agent, alcohol–ether modified polyhydroxy polymer as the foam stabilizer, modified hydroxyethyl starch as the viscosifier, and a xanthan gum derivative as the stabilizer. Aiming at a base fluid density of 0.85–0.95 g/cm³, an orthogonal experimental design produced a basic formula: (0.80–1.40%) viscosifier+(0.5–0.6%) stabilizer+(0.18–0.32%) foaming agent+(0.28–0.32%) foam stabilizer. Glass microspheres with a D90 particle size ≤ 70 μm, a density of 0.42–0.44 g/cm³, and a compressive strength ≥ 40 MPa were selected as the low-density particles. A low-density workover fluid system with an adjustable density range of 0.65–0.90 g/cm³ was developed. Laboratory tests indicated that increasing the low-density particle concentration from 0 to 50% led to a reduction in the system density from 0.85 to 0.65 g/cm³. After static aging for 48 h at room temperature and 90 °C, the density increments were less than 0.05 g/cm³ and 0.10 g/cm³ respectively. After repeated stirring at 3000 r/min for 5 min, the density increments were less than 0.01 g/cm³ and 0.03 g/cm³ respectively, demonstrating stable density under reservoir temperature conditions. Five fluid samples with densities ranging from 0.65 to 0.85 g/cm³ were injected at a constant rate of 0.5 mL/min into artificial fractures 0.1 mm wide. The pressure increase relative to water displacement ranged from 6.20 to 17.15 MPa, with lower-density fluids exhibiting higher pressure increases, indicating enhanced plugging performance with decreasing density. After plugging the core samples, 1.5 pore volumes of a 1% ammonium persulfate solution were directly injected and allowed to soak for 2 h to break the gel. The measured core permeability recovery rate ranged from 92.48 to 95.56%, demonstrating excellent formation protection. Field applications in two low-pressure gas wells, G-X and SN-X, completed in the tight Shanxi Formation sandstone and Majiagou Formation carbonate reservoirs with pressure coefficients of 0.76 g/cm³ and 0.43 g/cm³ respectively, involved the injection of 53.5 m³ and 34.3 m³ of the low-density workover fluid (densities 0.76 g/cm³ and 0.75 g/cm³). Fluid returns were observed at the wellhead with a loss rate below 0.01 m³/h. After workover, gas lift was directly initiated for fluid recovery. The post-workover gas production recovery rate reached 95.83% to 130%. This study confirms that the low-density workover fluid, by reducing the fluid column pressure in the wellbore, effectively mitigates the pressure burden on the fractured formation. This addresses the limitation of inadequate formation protection caused by excessive plugging strength during conventional workover operations.