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Seawater injection is commonly utilized for offshore wells to maintain or increase oil production; however, treatment for seawater before injection is always necessary to reduce or remove bacteria, dissolved oxygen, sulfate, and other impurities. Seawater typically has >2000 mg/L sulfate. Without proper sulfate removal, such high levels of sulfate can cause not only barium sulfate, strontium sulfate, and calcium sulfate scales, but also reservoir souring and H2S corrosion in the presence of sulfate reducing bacteria (SRB). Therefore, sulfate removal from seawater is critical before seawater injection into reservoir.
The sulfate level in the effluent of sulfate removal unit (SRU) is usually continuously monitored for quality assessment. SulfaVer 4 method of Hach Company is a commonly used technique for sulfate measurement, and it is based on turbidity measurement caused by barite formation. The residual scale inhibitors in the effluent of SRU were observed to interfere sulfate measurement by inhibiting barite formation. Twelve different types of scale inhibitors were investigated on their impact on sulfate measurement. It was found that phosphonate, phosphate ester, and certain poly-carboxylate scale inhibitors do not interfere sulfate measurement, but sulfonate co-polymer and phosphino-polycarboxylate scale inhibitors showed strong interferences, i.e., the measured sulfate levels were lower than the actual concentrations. Several pre-treatments for the test sample were attempted to remove the interference. One pre-treatment method, called “Fe2+ thermal aging”, was found to completely removed scale inhibitor interference on sulfate measurements without causing any side effect. The method has been verified with both synthetic brine and field brine. This pre-treatment method can also help improving the accuracy of residual scale inhibitor analysis.
Many asset owners struggle to identify the root cause of fluctuating corrosion rates due to unreliable inspection data. Facilities worldwide are tasked with monitoring thousands of Condition Monitoring Locations (CMLs) with established NDE techniques such as manual ultrasonic testing and radiography. While these techniques can provide valuable “snapshots” of the condition of particular locations, limitations and inherent errors can compound leading to ill-advised decision making. Manually taken thickness data can vary greatly and result in unwarranted complacency or excessive and costly inspections.
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The polycondensation of silicate to form colloidal silica is a well-known process. Silica formation takes place through an SN2-like mechanism that involves an attack of a mono-deprotonated silicic acid molecule on a fully protonated one. Thus, monomeric silicate species produce silicate dimers, and oligomers, and eventually form colloidal silica particles. Nevertheless, this straightforward silica chemistry can be profoundly affected by the presence of certain metal cations, such as calcium, magnesium, aluminum, and iron. When such cations are present in a process water they enhance the rate of polymerization of silicate ions and induce the formation of metal silicate precipitates.
Geothermal energy is a promising choice for alternative energy resources due to its reliability and low CO2 emissions. One way to harness this energy, is to extract hot fluid from a geothermal well. Geothermal fluids are a complex medium with different physical and chemical properties depending on the location and depth of a geothermal well. Thus, these fluids can be corrosive to the geothermal power plant depending on the corrosivity class. The geothermal power plant consists of various parts, such as pipelines and heat exchangers. For continuous power generation, this power plant should be safe and durable. Therefore, it is important to protect the infrastructure in this environment from corrosion.