The presence of black powder in natural gas pipelines can lead to equipment erosion, valve failure, instrumentation malfunction, and increased pressure drop. However, despite its impact on downstream and midstream operations, black powder production is poorly understood. In the present work, black powder formation as a result of corrosion was investigated by simulating sales gas conditions in a glass cell. Steel specimens were systematically exposed to a range of CO2, H2S, and O2 partial pressures at differing water condensation rates. The potential for hygroscopic material assisting black powder formation was also investigated. Friable corrosion products found in dewing conditions consisted of siderite, mackinawite, and hematite. The expected mass of corrosion products, as determined from experimental corrosion rates, are in line with the high levels of black powder in field production. The presence of hygroscopic NaCl crystals facilitated corrosion at relative humidities as low as 33%.
Black powder, particles which can be entrained by a natural gas stream, is a common problem in natural gas pipelines and if left unchecked can erode equipment, induce greater pressure drops, and clog instrumentation.1 Black powder may contain corrosion products, salt, dirt, and other materials such as those trapped in the pipeline during construction. Previous studies examining the composition of black powder have found primarily iron oxides and iron sulfides, but iron oxyhydroxides, iron carbonate, and elemental sulfur were also reported.2-5 The frequent occurrence of the aforementioned species have led researchers to conclude black powder is predominantly a result of corrosion.1-6
Corrosion in natural gas pipelines is typically caused by the presence of CO2, H2S, and O2 with liquid water. CO2 and H2S are known to be present within natural gas at various concentrations, but O2 is rarely reported. Exogenous oxygen ingress is attributed to be the primary source of O2 in natural gas and can lead to concentrations ranging from 0-0.03 vol%.2,7 Liquid water may seldom occur as the gas is dehydrated to 7 lbs H2O/MMscf (0.112 mg/l) or lower to reduce the risk of internal corrosion, however upsets in gas dehydration units may release enough water for condensation to be feasible. Measured dew points of water in the sales gas network were reported by Sherik, et al.2 The sales gas moisture content consistently exceeded the maximum moisture level of 7 lbs/MMscf (0.112 mg/l) risking dew formation. The measured water dew points were compared to meteorological data to examine the potential for water condensation on the steel pipeline. Winter ambient temperatures were frequently below the water dew point temperatures measured, therefore, water condensation was deemed likely.