Factors Controlling pH and Optimum Corrosion Mitigation in Chloride-Bearing Geothermal Steam at The Geysers
- Key words
- Power Generation; Production; Brine Technology; USA; California; Geysers; Scrubbing; Corrosion; Steam Chemistry; Acid; Noncondensable Gas; pH; Separators; Gathering System; HC1; Case Histories; Chloride; Sodium Hydroxide; Caustic; Coldwater Creek Steam Fi
- Location
- The Geysers, California
- Conference
- Geothermal Resources Council Transactions
- Year
- 1990
- Session
- Corrosion; Chloride; Scrubbers; Brine chemistry; Computer mo
- Language
- English
Abstract
A chloride (C1) scrubbing water and sodium hydroxide (NaOH) injection system has been tested for corrosion mitigation of superheated, C1 bearing geothermal steam (38-94 ppmw) in the northwest portion of the Geysers in California. Corrosion has been successfully mitigated by maintaining a pH of 8 to 9 in the liquid phase. The liquid is removed along with greater that 90% of the C1 by a vertical separator. The dissociation of the major soluble gaseous constituents of geothermal steam; carbon dioxide (CO2), hydrogen sulfide (H2S) ammonia (NH3) and possibly boric acid (H2BO3) buffer the pH in the liquid phase and should be considered for optimizing corrosion mitigation. Modeling CO2, H2S and NH3, with a chemical computer modeling program, ONEBOX, demonstrates that these gases compete with NaOH in the liquid phase to determine the pH of the system. Preliminary results indicated that this modeling technique may help to develop process parameters for optimizing NaOH injection for corrosion mitigation in steam wells with varying chemistry.
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