Abstract
Sandstone acid systems, which are composed of HCl and HF, are commonly used to remove the formation damage in sandstone reservoirs. However, to perform any treatment using these acid systems, a preflush and/or a postflush of HCl plain acid must be injected to eliminate CaF2 precipitation and secondary precipitation. In this study, a new sandstone acid formulation was developed that can be used as a one-step sandstone acid system (OSSA). This system eliminates the requirement of preflush and postflush HCl acid stages, reduces the treatment complexity, reduces the HCl requirements, and reduces the overall treatment/rig time.
A coreflood study was conducted using different sandstone cores at 180°F. In additional to quartz, the tested cores had varying amounts of clay mineral, feldspar, and carbonate. Consequently, they can be used to judge the performance of the new OSSA system.
Based on the experimental results, regular sandstone acid must be used with a preflush stage of HCl acid to maximize its performance and eliminate CaF2/MgF2 precipitation. The needs of the postflush stage must be confirmed as it can cause damage for sandstone that has HCl sensitive clay mineral. All selected one-step sandstone acid formulations (Acids A, B, C, and D) were able to successfully treat Bandera sandstone cores. For Bandera sandstone cores, increasing HCl/HF ratio increased the permeability enhancement and reduced the injected acid volume. Using the same acid volume and composition, a higher permeability enhancement was observed for the core that had less clay and carbonate content. Based on HCl:HF ratio and sandstone composition, a minimum acid volume is required to achieve a permeability enhancement. For the Bandera sandstone formation, only 8 PV of the OSSA system was required to achieve 26% permeability enhancement. However, for a Berea sandstone core that had less clay mineral, 4PV of OSSA system increased the permeability by 86%. The feldspar amount in the composition of sandstone can significantly impact the permeability enhancement of Acid C, while kaolinite amount has nearly no effect. A corrosion test was conducted at 180°F for 6 hr using a two pipe grades (Cr-13 and N-80). Two types of corrosion inhibitor were evaluated at different concentrations. All tested formulas had a very low corrosion rate (less than 0.03 lb/ft2). For both corrosion inhibitor types, corrosion rate was increased by reducing the HCl/HF ratio and/or inhibitor concentration.
