ABSTRACT
Many acidic geothermal wells with low-carbon steel casing materials benefit from the application of pH control chemicals such as NaOH. However, at high temperatures this can result in rapid scaling by anhydrite. In addition oxidation of iron in acid wells can lead to reductive deposition of heavy metals and in localized galvanic corrosion. Control of production fluid pH can require frequent adjustment of the NaOH addition. Corrosion inhibitors have been proposed as an alternative to pH adjustment in mildly acidic geothermal wells both for control of corrosion and scaling as well as for control of heavy metal deposition. In this study, a commercial corrosion inhibitor was used to quantify the level of corrosion mitigation of K55 casing material in simulated acidic geothermal electrolyte at different pH values and inhibitor concentrations. Results showed a decrease in corrosion rate as a function of increasing pH without inhibitor addition and a decrease in corrosion rate of over 90% with inhibitor addition at the lowest pH tested. The percentage decrease in corrosion rate was less at the higher pH values tested where the inhibitor free corrosion rates were lower and presumably controlled, in part, by iron sulfide/iron oxide formation.
INTRODUCTION
One of the most common problems related to geothermal industry is the chemistry of the geothermal fluids which sometimes contain quite considerable concentrations of minerals and gases, which can cause scaling and corrosion in wells and surface installations which the geothermal fluids flow through.1 Many of these technical problems have been solved, or minimized at least, by improved well design and well operation, proper material selection and chemical treatment of the geothermal fluids, including use of chemical inhibitors. Many geothermal production wells have highly acidic fluid discharges. Monitoring of corrosion in these acid-discharging wells shows that corrosion rates are higher than acceptable for commercial well utilization target lifetimes of more than 25 years. One of the methods to reduce corrosion is to modify the chemistry of the acidic fluid by neutralization using a base such as NaOH. However, in many cases, introducing NaOH poses a risk of mineral scaling and wellbore blockage, particularly at temperatures over 200°C. Such mineral deposition can require a mechanical work-over to make the well usable again.2, 3
