Oil and gas recovery systems vary around the world, but the same techniques apply. Primary recovery usually brings natural gas, oil and water to the surface with hydrogen sulphide (H2S) as a potential contaminate. Secondary recovery involves the injection of water into the well, which brings up natural gas, oil, lots of water and potentially H2S.
If there’s water, the potential for corrosion is higher. As fields become less productive, tertiary recovery becomes necessary, which requires the addition of water and carbon dioxide (CO2) to the well. That brings up even more corrosive brew—natural gas, oil, water, CO2 and H2 S. Inhibitors are normally used to control the corrosive effects but without a monitoring program using real-time values, no one really knows what combination of inhibitors would best minimize the corrosive effect on the process line.
For many years, metal coupons have been used to monitor corrosion in pipelines. They’re weighed, inserted into the process stream and after three to six months they’re removed, cleaned and checked for weight loss. This method is still used extensively to measure pipe wall thickness by determining an average weight loss over time. Ultrasonic testing using Smart Pigs (inspection vehicles that move inside pipelines) also measures pipe wall thickness, but the data generated is historical at best, and provides only an average corrosion rate over time.
Processes or process flows through pipelines are not always steady state; there are variations that occur over time, and these variations can be critical to the internal corrosion of a pipeline. That’s why it’s important to understand those variations and when they occur. Improvements over coupons have been made with linear polarization resistance (LPR) and electrical resistance (ER) probes, but they provide more general corrosion data over a more realistic time frame.
Localized corrosion (or pitting) has caused catastrophic failures to pipelines, 25% to 40% of which could be resolved if there was a way to monitor that occurrence. Pepperl+Fuchs’ CorrTran MV combines LPR and harmonic distortion analysis (HDA) to measure general corrosion and electrochemical noise (ECN) to measure localized corrosion. Its real-time analysis tells the operator what’s going on inside the piping and how that corrosion is affected by other process variables. Data is transmitted via a 4-20 mA signal using the HART protocol to the control room or (via a data dump through a USB port) to a computer.