home page / Technical Documentation Center & Engineering Guide
How to Evaluate Scale, Silica & Corrosion Risks in Geothermal Lines
Calcium carbonate, amorphous silica and corrosion management from wellhead to reinjection well in geothermal energy, district heating and greenhouse lines.
Risk analysis in geothermal fluid (brine) management cannot be made by looking only at aboveground plate exchangers. As the fluid rises from the well, as the pressure decreases, dissolved carbon dioxide (CO₂) passes into the gas phase (flashing); This can rapidly raise the pH and initiate calcium carbonate (CaCO₃) precipitation further into the well or at the wellhead valves.
As the temperature decreases in the exchangers along the line, the silica (SiO₂) saturation limit is exceeded and amorphous silica/metal silicate accumulation comes into play. Therefore, Elif Çevre Kimya's geothermal conditioning approach; It treats the downhole/wellhead, separator, exchanger and reinjection line as separate control points.
The weakening of heat transfer and the increase of differential pressure in plate heat exchangers strengthen the suspicion of scale or silica; However, it does not alone prove which mechanism is dominant. While calcium carbonate reacts readily with acid, polymerized silica or iron sulfide deposits do not dissolve with standard acidic washing.
In addition, high chloride, dissolved CO₂ and hydrogen sulfide (H₂S) gases in the geothermal fluid pose a serious corrosion risk in metal pipes and equipment. The antiscalant, silica dispersant or film-forming corrosion inhibitor with high thermal stability to be applied should be selected based on field data.
The fluid chemistry, temperature and gas ratio of geothermal wells vary from field to field and even between wells in the same field. As clearly stated on our site, fixed dosing is not recommended without brine analysis and corrosion coupon data. Injection depth, position of the dosing nozzle, coupon weight loss measurements and exchanger cleaning periods should be recorded together.
Line-Length Evaluation Starting at the Well Exit
Risk analysis in geothermal fluid (brine) management cannot be made by looking only at aboveground plate exchangers. As the fluid rises from the well, as the pressure decreases, dissolved carbon dioxide (CO₂) passes into the gas phase (flashing); This can rapidly increase pH, initiating calcium carbonate (CaCO₃) precipitation further into the well or at the wellhead valves. As the temperature decreases in the exchangers along the line, the silica (SiO₂) saturation limit is exceeded and amorphous silica/metal silicate accumulation comes into play. Therefore, Elif Çevre Kimya's geothermal conditioning approach; It treats the downhole/wellhead, separator, exchanger and reinjection line as separate control points.
Not Reading Heat Exchanger Performance with a Single Symptom
The weakening of heat transfer and the increase of differential pressure in plate heat exchangers strengthen the suspicion of scale or silica; However, it does not alone prove which mechanism is dominant. While calcium carbonate reacts readily with acid, polymerized silica or iron sulfide deposits do not dissolve with standard acidic washing. In addition, high chloride, dissolved CO₂ and hydrogen sulfide (H₂S) gases in the geothermal fluid pose a serious corrosion risk in metal pipes and equipment. The antiscalant, silica dispersant or film-forming corrosion inhibitor with high thermal stability to be applied should be selected based on field data.
Verifying Dosage with Brine Analysis and Corrosion Coupon
The fluid chemistry, temperature and gas ratio of geothermal wells vary from field to field and even between wells in the same field. As clearly stated on our site, fixed dosing is not recommended without brine analysis and corrosion coupon data. Injection depth, position of the dosing nozzle, coupon weight loss measurements and exchanger cleaning periods should be recorded together.
Field Control and Monitoring List
Chemical dosage and system capacity decisions should be determined by analysis and facility conditions; There is no guarantee of fixed dosage or performance.
- Brine temperature, pressure, pH, calcium, bicarbonate and silica (SiO₂) analysis at the wellhead and exchanger outlet
- Control of downhole or wellhead dosing nozzle position below the CO₂ gas flashing point
- Monitoring amorphous silica saturation index (SSI) at exchanger outlet temperature
- Monitoring the metal loss rate (mpy) and deposit character with corrosion coupons on the line
- Verification of inhibitor formulation suitable for high well temperature (thermal stability)
- Review Geothermal Conditioning Chemicals
- Geothermal Brine Analysis & Request a Quote
- 17. The Role of Dispersant and Process Water in Micronized Calcite Wet Grinding
- 18. How to Control the Use of Inhibitors in the Iron-Steel Pickling Line?
- 19. Foam and Slime Control in Paper and Corrugated Cardboard Production
- 20. How to Establish a Chemical Supply Plan in an Industrial Facility?