The Supercritical Carbon Dioxide Corrosion Test Facility is equipped with 3 high-temperature, high-pressure vessels and a gas-phase Fourier transform infrared spectrometer (FTIR) for simultaneous in situ monitoring of key contaminants. This paper outlines the capabilities of this new National Institute of Standards and Technology facility.
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Top of line corrosion (TLC) is a specific corrosion mechanism observed in the oil and gas industry. This phenomena occurs under stratified or wet-gas flow regimes when the upper internal pipeline walls are sufficiently cooled (by heat transfer to the surrounding outer environment), promoting local condensation of water vapor. Carbon dioxide (CO2) and organic acids dissolving into the condensed water generate a change in the solution chemistry, ultimately influencing the corrosion kinetics of the contacting carbon steel.
New gas field expansion will provide offshore facilities to process non-associated gas, where the newgas gathering system takes non-associated gas from offshore gas wells and transports it throughpipeline to onshore processing plants. The gas is very corrosive due to high levels of H2S and CO2 acidgases content. Further hydrate control is achieved by injecting mono ethylene glycol (MEG).
Corrosion-related losses represent approximately 30% of the hydrocarbons extraction and treatment industry's failures, with a total annual cost of US$ 1.372 billion. The oil&gas industry has widely recognized the importance of implementing effective prediction and management systems to reduce costs and guarantee compliance with safety, health, and environmental regulations. In this context, it is safe to narrow the oilfield corrosion problem mainly towards the two most severe degradation cases observed during operation: the sweet CO₂-related and H₂S-related corrosion.
A fit for purpose qualification of new corrosion inhibitors was carried out for in a gas and condensate field. The depth of production well is 4,500 m and the bottom hole temperature and pressure are 180ºC and 50 MPa respectively. The methodology and result of the inhibitor evaluation under a sweet condition was summarized. Two brands of corrosion inhibitors had been used each for production tubing and flowline in the field. New corrosion inhibitors were evaluated for the both applications. The corrosion inhibitor efficiency for high shear service and the adhesion tendency were evaluated with a rotating cage autoclave and a dip and drip experiment respectively. In order to evaluate the tendency of emulsion forming, oil, brine and an inhibitor were poured into a centrifuge tube and it was shaken intensely. Gas chromatograph - mass spectrometer (GC-MS) and Fourier transform infrared spectroscopy (FT-IR) were studied to measure the residual amount of inhibitor. Finally, the field trial was conducted with a new inhibitor. The new inhibitor was adopted successfully for the both services. The risk of emulsion forming became lower because the mixing of two brands of inhibitors was avoided. Reducing the number of the chemicals contributed to reduction of the operation cost too.
Modified 13Cr (UNS S41426) (M13Cr) are advantageous as components for wellbores in oil and gas upstream units due to their high strength capabilities and tremendous corrosion resistance in sweet environments with minimal H2S levels. However, previous studies speculate disparities between an overestimation in the application limits for the 110 ksi grade material. Previous experimental results associate this to microstructural differences from varying heat treatments. The proprietary procedures used to manufacture, emphasize a lack of quality control among suppliers.