Formation-Damage Mechanism and Gel-Breaker-Free Drill-In Fluid for Carbonate Reservoir

Abundant oil and gas reserves have been proved in carbonates, but formation damage affects their production. In this study, the characteristics and formation-damage mechanism of the carbonate reservoir formation of the MS Oilfield in the Middle East were analyzed—utilizing X-ray diffraction, a scanning electron microscope, slice identification, and mercury intrusion—and technical measures for preventing formation damage were proposed. An ‘improved ideal filling for temporary plugging’ theory was introduced, to design the particle size distribution of acid-soluble temporary plugging agents; a water-based drill-in fluid, which did not require gel-breaker treatment, was formed, and the properties of the drill-in fluid were tested. The results showed that the overall porosity and permeability of the carbonate reservoir formation were low, and that there was a potential for water-blocking damage. There were micro-fractures with a width of 80–120 μm in the formation, which provided channels for drill-in fluid invasion. The average content of dolomite is 90.25%, and precipitation may occur under alkaline conditions. The polymeric drill-in fluid had good rheological and filtration properties, and the removal rate of the filter cake reached 78.1% in the chelating acid completion fluid without using gel breakers. In the permeability plugging test, the drill-in fluid formed a tight plugging zone on the surface of the ceramic disc with a pore size up to 120 μm, and mitigated the fluid loss. In core flow tests, the drill-in fluid also effectively plugged the formation core samples by forming a thin plugging layer, which could be removed by the chelating acid completion fluid, indicated by return permeability higher than 80%. The results indicated that the drill-in fluid could mitigate formation damage without the treatment of gel breakers, thus improving the operating efficiency and safety.