The control of multiphase flow corrosion in oil and gas industry is one of the biggest challenging tasks. Since the 1990s, several organizations have established and operated large-scale flow loops to simulate and reproduce the field service environment of oil and gas pipelines. Based on comparison and investigation of the above loops, a new and advanced system, including several four inches internal diameter loops for studying corrosion under multiphase flows, was successfully built by us. By using this system, multiphase flows with various combinations of gas, water, oil and sand can be realized at the highest temperature of 140 oC and the highest pressure of 10 Mpa. Moreover, some loops in this system can adjust pipeline at different angels from 0 to 90°, which allow horizontal/vertical/sloping conditions to be simulated in laboratory. Many advanced measuring and monitoring technologies, such as Particle Imaging Velocimetry (PIV), high speed video camera and LPR/ER probe, are employed for simultaneously recording flow events and corrosion rates. An inhouse plane three-electrode probe is employed for conducting in situ electrochemical measurements. Such technologies would allow deep researching of corrosion behaviors and mechanisms in multiphase flow environments. Moreover, a new software based on Fluent and the existing multiphase corrosion models was developed to realize the numerical simulation of multiphase flow in loop.
This paper describes the performance of film persistent corrosion inhibitors that are effective at fairly high temperatures and in systems that see large amounts of carbon dioxide (CO2). Use of batch treatment with the correct chemical, at the proper frequency resulted in substantial decrease in operating cost.
For certain CCS (carbon capture and storage) projects, ship transport of captured CO2 to the storage site may prove more optimal than pipeline transport. The CO2 will be transported under two-phase conditions at low temperature (-10 to -25 °C) and moderate pressure (1.7 – 2.7 MPa), which are quite different from the typical pipeline transport conditions (5 – 60 °C and 7 – 12 MPa). Corrosion under pipeline conditions has been relatively well studied, and several conditions (impurity mixtures) that results in formation of corrosive acids have been identified. In contrast, almost no research exists on corrosion under ship transport conditions when the CO2 contains impurities. The present work tested corrosion of carbon steel at -25°C in CO2 with different concentrations of H2O, H2S, O2, NO2 and SO2. The experiments demonstrated that certain combinations of impurities gave no chemical reactions and no corrosion, while other combinations resulted in formation of solids and corrosive components that attacked carbon steel. The mass loss corrosion rate was around 0.1 mm/y.
In China, some underground gas storages (UGS) would be built to reserve the gaseous coal gas (CO, H2, CO2, H2O, etc.). Gaseous hydrogen induced hydrogen embrittlement (HE) and CO2 corrosion could possess great threat to the safety of OCTG in UGS. Fitness-for-purpose research of OCTG materials is urgently expected to screen out the suitable material for tubing application in UGS.
HE resistance and CO2 corrosion of OCTG materials (C110, 3Cr-90S, 13Cr-110 and 13Cr-110S) were investigated by slow strain rate testing and weight loss tests in UGS environments containing CO2 and H2. SSRT results show that both elongation ratio and reduction in area ratio of C110, 13Cr-110 and 13Cr-110S were more than 80%, except for 3Cr-90S. In addition, 3Cr-90S and 13Cr-110 tested in H2/CO2 environments possessed embrittled regions and secondary cracks, respectively. Weight loss test results show that C110 and 3Cr-90S exhibited high corrosion rates, which were classified as severe corrosion followed by qualitative categorization of corrosion rates for oil production systems in NACE RP0775. For stainless steels (13Cr-110 and 13Cr-110S), the corrosion rates were very low (low corrosion). Combined with the above results, 13Cr-110S could be the suitable OCTG material for UGS containing gaseous coal gas.
Laboratory testing of corrosion inhibitors under high temperature high pressure (HTHP) conditions is challenging. HTHP testing has been traditionally performed in closed systems with fixed liquid/gas volume and testing results are usually influenced/compromised by the accumulation of ferrous ions and corrosion products. The aim of the work is to optimize corrosion inhibitor testing conditions at HTHP to generate results of better reliability. The corrosion of carbon steel by CO2 at HTHP was assessed using small working electrodes of large liquid volume-to-sample surface area in autoclaves. The effect of CO2 partial pressure was also investigated. The blank and inhibited corrosion rates were monitored by linear polarization resistance (LPR) and the morphology of coupon surface was measured by vertical scanning interferometry (VSI). The testing results were deemed to be more representative of the field service environment when the amount of ferrous ions and corrosion products was reduced due to the usage of small working electrodes.