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Evaluating the Damage Caused by Calcium Sulfate Scale Precipitation During Low- and High-Salinity-Water Injection
- Mohamed A. Mahmoud (King Fahd University of Petroleum and Minerals)
- Document ID
- Society of Petroleum Engineers
- Journal of Canadian Petroleum Technology
- Publication Date
- May 2014
- Document Type
- Journal Paper
- 141 - 150
- 2014.Society of Petroleum Engineers
- 6.4.1 Waterflooding, 5.3.5 Scale, Sand, Corrosion, and Clay Migration Control, 5 Production and Operations, 6.4 Primary and Enhanced Recovery Processes, 6 Reservoir Description and Dynamics, 5.3 Production Enhancement
- low salinity, chelating agents, damage, high salinity, calcium sulfate
- 8 in the last 30 days
- 421 since 2007
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Scale deposition is a serious oilfield problem, when two incompatible waters interact chemically and precipitate minerals. Typical examples are seawater with a high concentration of sulfate ions and formation water with high concentrations of calcium, barium, and strontium ions. Mixing these waters may cause precipitation of calcium, barium, and/or strontium sulfate. The removal of the entire sulfate content from seawater might be a costly process and requires highly advanced techniques (nanofiltration). This study was conducted to investigate the damage caused by deposition of calcium sulfate precipitation and to describe the damage by use of the material-balance method, and then a new technique is proposed to prevent the damage caused by calcium sulfate scale. Coreflooding experiments were performed to assess the damage caused by calcium sulfate and a computed-tomography (CT)scan was used to locate the damage inside the core. Chelating agents, such as hydroxyl ethylene diamine triacetic acid (HEDTA), ethylene diamine tetra acetic acid (EDTA), and hydroxy ethyl imino diacetic acid (HEIDA), were used to prevent scale deposition in the Berea sandstone cores. The pressure drop across the core caused by scale precipitation will be predicted analytically. The results of the experimental data showed reduction of permeability by 20% from its initial value after seawater injection, caused by calcium sulfate precipitation. The results of the new analytical model showed that in approximately 1 month, the injection will stop or the injection pressure will exceed the fracture pressure of the formation. High-salinity-water injection caused severe formation damage, and the injectivity declined faster compared with the low-salinity-water injection. The material-balance calculations showed a good match between the experimental, field, and predicted data. The developed model of the pressure drop caused by calcium sulfate precipitation was used to predict the pressure drop across the core, and its result was in a good match with the experimental results. The new method was effective in preventing and removing sulfate precipitation.
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