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1) Higher bottom hole temperature may lead to water condensation: The accompanied water vapour is likely to dew out along the flow path
2) Higher CO2 / H2S partial pressure lead to more aggressive corrosion.
3) Often presence of organic fatty acids
4) Higher gas rate removal of protective iron cabonate (FexCO3) scaling.
The corrosion risk in production under stimulation, e.g. water flooding, steam flooding, CO2 flooding etc.
1) oxygen ingression in production fluid, which is normally cathodic reaction controlled(reduction of oxygen) through oxygen diffusion rate.
2) Higher water cut in produced fluid
3) Microbial growth due to field souring
4) Removal of hardness in water re-injection system
5) Elevate temperature due to introduce of hot water, steam or combustion.
Methods of Inhibitor Application in Gas Production
1) Continuous Treatment: 25-100 ppm CI , 95% availability to achieve satisfied results.
2) Intermittent Treatment: Thousands ppm level, treated every 3-6 months, in some extreme case, 12 months interval is potential. Higher density(using ZnCl2 or glycol formula) dispersible or stick type.
3) Squeeze Treatment: Higher concentration, inject into formation and release gradually with flow back production fluid. Potential formation damage.
4) Tubing Displacement: Fill or brush tubing with CI.
5) Rescue “Killed ” wells: by foaming, gas squeezing, reeled tubing,
6) Packer fluid corrosion inhibitor left a quiescent fluid in tubing-casing , casing-formation annuli, shut-in wells