Mixing Hydrochloric Acid and Seawater for Matrix Acidizing: Is It a Good Practice?

Abstract

In offshore operations where seawater is commonly used to prepare hydrochloric acid, calcium sulfate precipitation, the potential of which can greatly reduce the effectiveness of these treatments. This is because high concentration of calcium produced in spent acid mixed with high level of sulfate in seawater. However, a few studies have provided evidence for this problem and the effect of calcium sulfate precipitation on acid treatments has not been fully examined.

In this work, core flood experiments at 0.5, 1, and 5 cm³/min flow rates were performed at 25°C to investigate formation damage due to calcium sulfate precipitation during matrix acidizing treatment. Austin Chalk cores (6 in. length and 1.5 in. diameter) with a permeability of 10 md and synthetic seawater were used. The core permeability before and after acid treatment, pressure drop response, calcium ion, sulfate ion, and pH values in the core effluent samples were measured. Solids collected in the core effluent samples were analyzed using XPS technique. Both acid prepared in seawater and in deionized water were examined.

Results showed that calcium sulfate precipitation occurred when seawater was used in any stage during matrix acidizing including preflush, post-flush, or in the main stage. Injection rate was the most important parameter that affected calcium sulfate precipitation; permeability reduction was significant at low flow rates, while at high rates wormhole breakthrough reduced the severity of the problem. This work confirms the damaging effect of preparing hydrochloric acid using seawater for acid treatments.

Introduction

Formation damage caused by calcium sulfate scale precipitation when formation temperature changes, formation pressure drops, brine salinity changes, or incompatible fluids are introduced into formation is an old and persistent problem in the oil industry (Vetter et al. 1982; Raju and Nasr-El-Din 2004). Scale deposits may occur in the near-wellbore region, tubing, and surface facilities. The consequence therefore could be production equipment failure, increased maintenance cost, and overall decrease in production efficiency (Abu-Khamsin and Ahmad 2005). Prevention of calcium sulfate precipitation requires extensive knowledge of formation mechanisms and inhibition treatment of calcium sulfate scale.

The most common calcium sulfate scale minerals found in the oilfield include anhydrite (CaSO₄), hemihydrate (CaSO₄•1/2H₂O) and gypsum (CaSO₄•2H₂O) (Kan et al. 2005; Schausberger et al. 2009).  Gypsum (CaSO₄•2H₂O) is the stable form below 45°C while anhydrite (CaSO₄) is stable above 93°C (Furby et al. 1967). The interest of this work is Gypsum (CaSO₄•2H₂O). The solubility of calcium sulfate in brine is influenced by many factors with ion concentration and temperature being the most important ones (Abu-Khamsin and Ahmad 2005).