Zero Solid Invasion Water-Based Drilling Fluid

Jafarov, Tural (Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (Fahd University of Petroleum & Minerals) | Al-Majid, Abdulaziz (Fahd University of Petroleum & Minerals) | Mahmoud, Mohamed (Fahd University of Petroleum & Minerals)



Reducing the filtrate volume and eliminating the solid invasion is very important and critical in drilling tight reservoir. This will eliminate water blocking which is the common problem in drilling tight gas formation.

The objectives of this study are to evaluate the effect of using sodium silicate, assess the changes of the rheological properties of water-based drilling fluid, determine filtrate volume and filter cake thickness, and optimize the concentration of sodium silicate to be used.

The obtained results showed that there was no effect of adding sodium silicate to the drilling fluid on density and pH. At room temperature, the optimum concentration of sodium silicate was 0.075 wt.% wt. which no change was observed in the yield point plastic viscosity ratio and at the same time, the plastic viscosity, yield point, and gel strength were enhanced. At higher temperature 120 and 170°F, the optimum concentration of sodium silicate was 0.075 wt.% which enhanced the rheological properties of the drilling fluid. Sodium silicate worked as a catalyst and as a result, it enhanced barite solubility at 200°F. The cumulative filtrate volume was decreased by 53% when using 0.075 wt.% of sodium silicate and the filter cake thickness was decreased by 65%. The retained permeability was 100% and the CT number before filtration and after removal was very closed, confirming no solid invasion was observed in the core.


In case of unconventional reservoirs, due to the complexity of drilling methods, formation damage by drilling fluids become more severe. The wells drilled for tight gas formations mainly suffers from water blockage problem. This is because of the much lower viscosity of gas than water, which water fills smaller pores of tight formation. Consequently, capillary forces cause water blockage.

There are several types of formation damage mechanisms. These mainly depend on composition and chemistry of drill-in fluid, used the bridging material, spurt loss characteristics of the drill-in fluid, the maximum level of overbalance drilling (Amanullah and Allen 2013). Ideal drill-in fluid should have degradable solids, minimum drill cuttings, reduced fluid invasion, not chemically reactive filtrate with formation fluid, filtrate that is not swellable with shale (Mandal et al. 2006).