Investigation of the precipitation of calcium sulfate scale during low and high salinity water injection in EOR processes in carbonate and sandstone reservoirs

Calcium sulfate scale is one of the most serious oilfield scale problems that could be formed in sandstone and carbonate reservoirs. Calcium sulfate may precipitate when injecting sea water with high sulfate content into formation contains brine with high calcium content. Mixing of sea water and formation brine may cause precipitation of calcium sulfate, barium sulfate and/or strontium sulfate. Sea water treatment does not remove the entire sulfate ions from the injected water, at least 100 ppm sulfate will remain and even this low concentration may cause damage. Enhanced oil recovery processes such as smart water injection which originally is diluted sea water also will cause calcium sulfate precipitation as the reduction of water salinity will increase the sulfate precipitation and decrease its solubility. This study was conducted to investigate the damage caused by deposition of calcium sulfate precipitation, describing the damage using material balance method and kinetic models, and then a new technique will be proposed to prevent the damage due to calcium sulfate. Several coreflood experiments were conducted using Berea sandstone and Indiana limestone cores at reservoir conditions of pressure and temperature using sea water (high and low salinity) and formation brines. Chelating agents that were used in this study are: EDTA, HEDTA, and HEIDA. High salinity water injection caused severe formation damage and the injectivity declined faster compared to the low salinity water injection. HEDTA and EDTA chelating agents at low concentrations performed better than HEIDA chelating agents in both Berea sandstone and Indiana limestone cores. HEDTA and EDTA chelating agents were able to prevent the damage due to calcium sulfate precipitation and also enhanced the core permeability.