Reliable corrosion inhibition in the oil and gas industry RR 1023 Research Report
The objective of the work was to undertake a literature review on the subject of corrosion inhibition in the offshore oil and gas industry to understand the current issues. The application of chemical corrosion inhibitors can significantly reduce the rate of corrosion of carbon steel pipelines due to the presence of CO2 and/or H2S. An inhibited corrosion rate of 0.1 mm/year can typically be achieved, which is largely independent of the uninhibited corrosion rate. The report covers the main factors affecting the effectiveness of chemical corrosion inhibitors; they are not effective against corrosion due to the presence of oxygen or microbacterial corrosion. High flow rates, high temperature, solids (either dissolved or suspended) and pre-existing corrosion can all have a negative effect on corrosion inhibitor effectiveness. The role of Key Performance Indicators (KPIs), the main factors affecting the performance of inhibition injection systems, and the levels of inhibitor availability that can be assumed at the design stage and achieved in practice are also discussed. This report and the work it describes were funded by the Health and Safety Executive (HSE). Its contents, including any opinions and/or conclusions expressed, are those of the authors alone and do not necessarily reflect HSE policy. You may reuse this information (not including logos) free of charge in any format or medium, under the terms of the Open Government Licence. To view the licence visit Some images and illustrations may not be owned by the Crown so cannot be reproduced without permission of the copyright owner. Enquiries should be sent to Objectives To undertake a literature review on the subject of corrosion inhibition in the oil and gas industry to understand the current issues. Main Findings • The application of chemical corrosion inhibitors can significantly reduce the rate of corrosion of carbon steel pipelines due to the presence of CO 2 and/or H 2 S. An inhibited corrosion rate of 0.1 mm/year can typically be achieved, which is largely independent of the uninhibited corrosion rate; • Various factors can affect the effectiveness of chemical corrosion inhibitors; they are not effective against corrosion due to the presence of oxygen or microbacterial corrosion. High flow rates, high temperature, solids (either dissolved or suspended) and pre-existing corrosion can all have a negative effect on corrosion inhibitor effectiveness; • The main Key Performance Indicator (KPI) used for assessing effectiveness of corrosion inhibitors is based on the proportion of time that …
The corrosion inhibitor availability model
The traditional corrosion inhibitor efficiency model is reviewed and shown to have some failings, particularly in the design of new facilities. This article discusses the problem of considering a single, deterministic corrosion rate and considers the distribution of corrosion rates about a mean value. It highlights the role of a corrosion inhibitor to reduce the mean corrosion rate and decrease the spread of corrosion rates. The article introduces a corrosion inhibitor availability model and a corrosion inhibitor risk category and discusses the limitations on the use of corrosion inhibitors. Data from BP's Prudhoe Bay operation is used to support the ideas discussed.
Full-scale measurements of SO2 gas phase concentrations and slurry compositions in a wet flue gas desulphurisation spray absorber
Abstract Two measurement campaigns were carried out at ENERGI E2's Asnaes Power plant, unit 5. The unit has a capacity of 620 MW e and is equipped with a wet flue gas desulphurisation (FGD) plant employing a counter-current spray absorber with five spray levels. In the first campaign, the power plant was firing Orimulsion ® with 2.85 wt% S resulting in a flue gas concentration of SO 2 exceeding 2000 ppmv. In the second campaign, the fuel applied was a low-S blended coal and the SO 2 concentration in the raw gas was around 400 ppmv. A novel probe for in situ sampling of gas phase concentrations in wet FGD spray absorbers was developed and applied for measuring axial profiles of the SO 2 gas phase concentrations in the absorber. The expected decrease in SO 2 concentrations along the height of the absorber was found in the spray section (from height 26.5 to 36.2 m) whereas the SO 2 concentration above the holding tank and below the gas inlet was quite low probably due to long local residence times in the region. Horizontal variations, due to somewhat different flow conditions near the column wall were investigated and the SO 2 concentrations were found to be higher near the wall. Measurements at different gross loads showed that the SO 2 gas phase concentration at a given position inside the absorber was roughly linearly related to the L/G ratio in the measuring interval. Turning off one of the lower spray levels, while burning coal with low S content, did not lower the overall removal efficiency of the absorber. However, the SO 2 gas phase concentration inside the lower part of the absorber was increased by a factor of 2–3. Measurements of slurry pH at different positions showed a decrease of approximately 0.5 units from the upper to the lower part of the absorber. The full-scale measurements provide a detailed set of experimental data for validation of mathematical models of a wet FGD spray absorber.