August 2024, Vol. 251, No. 8
Features
Corrosion Control: Options for Combating Damage Due to Black Powder in Pipelines
By Ramesh Singh, IEng Engineer
(P&GJ) — Black powder (BP) is an industry name for the abrasive, reactive particulate contamination present in all gas and hydrocarbon fluid transmission lines. Black powder ranges from light brown to black, and the mineral makeup varies per production field around the world.
The majority of black powder composition is ferrous or magnetic in nature. Other sources of black powder are from mill scale, from the pipe manufacturing process, through the high temperature oxidation of steel and flash rust created when the pipe is hydro tested.
These deposits are a cause of corrosion damage in the steel pipes, responsible for the reduction in the flow rate and drop in pressure. This makes the system inefficient, affecting productivity and creating potentially serious damage to the pipeline and system. Figure 1 shows the extent of deposit in a pipeline that was removed by pigging.
Formation, Prevalence
Black powder forms throughout the pipeline process: from producing formations, through well-piping and gathering lines, in reservoirs for fluid separation and along transmission pipelines.
After refinement, BP continues to build in gas plants and refineries, storage reservoirs, sales lines and finally, through to the end user. Black powder is a composite of friable corrosion products, found in dewing conditions, consisting of siderite (FeCO3), mackinawite (FeS) and hematite (Fe2O3).
The expected mass of corrosion products, as determined from experimental corrosion rates, are in line with the high levels of black powder that can be experienced. Varying dirt, such as silica and calcium, as well as chloride, sodium, and other material particulates, also contribute to the BP formation in pipeline and equipment.
Black powder results from chemical and bacterial reactions within hydrocarbon systems.
Bacterial activity includes sulfate-reducing bacteria (Deslfovibrio desulfuricans) and acid-producing bacteria (Clostridium), which are dependent on the reaction of water and iron to form the hydrogen sulfides that cause oxidization and in turn, BP.
Chemically, the three primary catalysts of BP contamination are moisture, H2S and temperature or pressure variance. Within pipeline transmission systems, ever-present moisture catalyzes bacterial and chemical corrosion of the carbon steel walls within pipelines and storage reservoirs. In refineries, process plants and storage reservoirs, if H2S is present, it will corrode all carbon steel components, creating more BP.
Severe temperature and pressure changes occur throughout the pipeline at city gates, processing plants and refineries, precipitating iron oxides, iron sulfides, and sulfur from the hydrocarbon gas or liquids. These particles have an affinity for themselves, and throughout the rest of the pipeline process, they will reach measurable levels, instantly causing clouds of BP in the flow.
The presence of BP 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, BP production is not very well understood.
As Baldwin reported in his 1997 paper, BP particles tend to be entrained in a natural gas stream. This is a common problem in natural gas pipelines. If left unchecked, BP can erode equipment and be responsible for greater pressure drops in the flow, as well as clog instrumentation. Black powder may contain corrosion products, salt, dirt and other materials, such as those trapped in the pipeline during construction.
Other studies have found that the composition of BP consists of iron oxides and iron sulfides, but the presence of iron oxyhydroxides, iron carbonate and elemental sulfur were also reported. The frequent occurrence of these species established that BP is product of corrosion activity.
Corrosion in natural gas pipelines is typically caused by the presence of carbon dioxide (CO2), hydrogen sulfide (H2S) and hydrogen sulfide (O2) in the presence of water. Carbon dioxide and hydrogen sulfide are known to be present within natural gas at various concentrations, but hydrogen sulfide is often not reported.
Exogenous oxygen ingress in the system is attributed to be the primary source of oxygen in natural gas, the concentrations of which range in percentage volume from 0 to 0.03 (vol%). Though the gas is typically dehydrated to 7 lbs H2O/MMscf (0.112 mg/l) or lower to reduce the risk of internal corrosion, water may still occur.
Measured dew points of water in the gas network were often reported, as dew formation and condensation take place in pipelines. Water accumulation at the steel wall may also occur if a hygroscopic material, such as salt, is present on the steel surface.
In addition to the above, the use of seawater as a hydrotest medium may also cause salt presence, especially as sea water residue, if the test water is not effectively rinsed. This is associated with BP formation and water carryover.
In the presence of an oxygen environment, the hygroscopic NaCl particles on steel activate corrosion cells in the relative humidities as low as 32%. Hygroscopic corrosion in CO2/H2S conditions is not as well studied, so the potential for BP production through hygroscopic corrosion processes remains unknown.
Surprisingly, the presence of water in a gas pipeline is often ignored as the primary cause for corrosion, since the concentrations of CO2, H2S and O2 are known to be adequate for corrosion to occur. It is to be noted that if the water content of the gas is high, then water may condense onto the steel surface, and initiate a corrosion cell.
However, if the water content is below the thermodynamic dew point temperature, then the presence of a hygroscopic material, like salt, may initiate a corrosion cell and the overall corrosion process.
Largely absent from the black powder discussion is the information relating to corrosion product separation, which is also referred to as spallation. A corrosion product layer can grow in a pipeline, but if that corrosion product cannot separate, spall or become entrained in the gas flow and be taken away from the system, then the adhering corrosion product forms the BP.
In CO2/H2S conditions, in gas pipelines experiencing dewing corrosion, FeS layers readily crumble and fall apart—a process often referred to as friable, this breaking away of corrosion product is often observed in FeS corrosion. Similar layers may be formed in gas pipelines which may ultimately lead to BP formation. H2S partial pressure and water condensation rate are considered critical to the development of the friable layers but the friability angle is not much.
The effect of CO2, H2S, and O2 concentrations on the development of corrosion product layers, due to dewing and hygroscopic corrosion, are better explored.
Traditional approach to a BP solution has been to use strainers or separators mesh. But the limitations of these approaches are that most cone strainers and separators mesh can stop contaminants in excess of 100 microns in size, and the problem involves sub-micron contaminants.
Preventive Measures
The majority of measures employed to deal with BP are reactive, as opposed to the proactive steps, such as pigging and chemical cleaners, resulting in significant down time and costs.
Currently, the proactive steps are very limited; they include treatment with corrosion inhibitors, especially to the sour gas pipelines. For low pressure systems, the use of lined pipe, replacing the steel pipe with plastic pipe, is another option.
Somewhere between the proactive and reactive steps are the use of ILI inspection and planned, frequent Pigging, to remove deposits. These are reasonably effective measures to control the BP deposit.
To reduce BP in a system, traditional filtration—consisting of cartridge filter elements manufactured from paper, fiberglass, or polymer media, with various rated filtration capabilities—is also employed. However, experience shows the limitations of these approaches, as they are often clogged and plugged off quickly, requiring costly change outs, which result in reduced production.
Some new magnetic approaches have been developed that have better effect on reduction of contaminants; however, as the system is magnetic, it can help remove magnetic byproduct of the reactions, but it has very little impact on nonmagnetic contaminants.
Author: Ramesh Singh, MS, IEng, MWeldI, is a retired engineer, and he now consults with various organizations, including his previous employer, The Gulf Interstate Engineering - Houston. He has worked for several years in the oil and gas industry in various capacities, as well as with associations including NACE (now AAMP) and the Welding Institute U.K.
References:
- R. Baldwin; Black Powder in the Gas Industry - Sources, Characteristics and Treatment (1997)
- R.E. Bedworth et al. The oxidation of metals at high temperatures, J. Inst. Met. (1923)
- A. Bhardwaj et al. Characterization of black powder in gas pipelines, Mater. Perform. (2016)
- R.B. Bird et al. Transport Phenomena, (2007)
- T.S. Khan et al. Review of black powder in gas pipelines – an industrial perspective
- Nat. Gas Sci. Eng. (2015)
- N. Birks et al. Introduction to the High Temperature Oxidation of Metals, Second Edition
(2006)
- F.A. Golightly et al. The relationship between oxide grain morphology and growth mechanisms for Fe-Cr-Al and Fe-Cr-Al-Y alloys, J. Electrochem. Soc. (1979)
- A.L. Hali et al. The use of preservation chemicals for extended shut-ins following hydrostatic testing of gas and service pipelines
- J. Holden et al. Vapor corrosion inhibitors in hydro-testing and long term storage applications
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