Corrosion pipelines

The end product specification of a process may be defined by a customer (e.g. gas quality), by transport requirements (e.g. pipeline corrosion protection), or by storage considerations (e.g. pour point). Product specifications normally do not change, and one may be expected to deliver within narrow tolerances, though specification can be subject to negotiation with the customer, for example In gas contracts. 

To prepare gas for evacuation it is necessary to separate the gas and liquid phases and extract or inhibit any components in the gas which are likely to cause pipeline corrosion or blockage. Components which can cause difficulties are water vapour (corrosion, hydrates), heavy hydrocarbons (2-phase flow or wax deposition in pipelines), and contaminants such as carbon dioxide (corrosion) and hydrogen sulphide (corrosion, toxicity). In the case of associated gas, if there is no gas market, gas may have to be flared or re-injected. If significant volumes of associated gas are available it may be worthwhile to extract natural gas liquids (NGLs) before flaring or reinjection. Gas may also have to be treated for gas lifting or for use as a fuel. 

The most common contaminants in produced gas are carbon dioxide (COj) and hydrogen sulphide (HjS). Both can combine with free water to cause corrosion and H2S is extremely toxic even in very small amounts (less than 0.01% volume can be fatal if inhaled). Because of the equipment required, extraction is performed onshore whenever possible, and providing gas is dehydrated, most pipeline corrosion problems can be avoided. However, if third party pipelines are used it may be necessary to perform some extraction on site prior to evacuation to meet pipeline owner specifications. Extraction of CO2 and H2S is normally performed by absorption in contact towers like those used for dehydration, though other solvents are used instead of glycol. 

Parker, M. E., Pipeline Corrosion and Cathodic Protection, Gulf Publishing Co., Houston, Texas... 

Peabody, A. W., Control of Pipeline Corrosion, NACE, Houston (1971)... 

Technical Committee Reports of the National Association of Corrosion Engineers, USA, on pipeline corrosion control, including Statement on Minimum Requirements for Protection of Buried Pipelines , Some Observations on Cathodic Protection Criteria , Criteria for Adequate Cathodic Protection of Coated Buried Submerged Steel Pipelines and Similar Steel , Methods of Measuring Leakage Conductance of Coatings on Buried or Submerged Pipelines , Recommended Practice for Cathodic Protection of Aluminium Pipe Buried in Soil or Immersed in Water ... 

Coatings, cathodic protection, and chemical additives are used extensively to prevent internal and external pipeline corrosion. The excessive use of incompatible chemical additives has caused severe problems in gas-transporting systems. Costs arising from these problems often exceed the costs of the chemicals themselves. The careful evaluation and selection of chemical additives can minimize these problems and reduce operating costs [I860]. 

Inhibitors may be classified according to their solution properties as either oil-soluble inhibitors, water-soluble inhibitors, or dispersible inhibitors. Chemical inhibitors act as film formers to protect the surface of the pipeline. Corrosion inhibitors, used for the protection of oil pipelines, are often complex mixtures. The majority of inhibitors used in oil production systems are nitrogenous and have been classified into the broad groupings given in Table 11-4. Typical corrosion inhibitors are shown in Table 11-5. For details, see also Chapter 6. 

It is visualized that the proposed coal slurry pipelines could be used as biological plug flow reactors under aerobic conditions. The laboratory corrosion studies under dynamic test conditions show that use of a corrosion inhibitor will limit the pipeline corrosion rate to acceptable levels. 

About 80% pyritic sulfur removal has been achieved by microbial desulfurization of Illinois 6 and Indiana 3 coals using T. ferrooxidans in laboratory shake-flask experiments and in a two-inch pipeline loop. The 10 to 25 wt% coal/water slurry was recirculated at 6-7 ft/sec for 7 to 12 days at 70-90°F. Results also show that the rates of bacterial desulfurization are higher in the pipeline loop under turbulent flow conditions for particle sizes, 43 to 200/m as compared to the shake-flask experiments. It is visualized that the proposed coal slurry pipelines could be used as biological plug flow reactors under aerobic conditions. The laboratory corrosion studies show that use of a corrosion inhibitor will limit the pipeline corrosion rates to acceptable levels. 

Andres B Peratta, John M W Baynham, and Robert A. Adey. A Computational Approach for Assessing Coating Performance in Cathodically Protected Transmission Pipelines. CORROSION 2009, Paper 6595 Atlanta, Georgia. NACE International 2009. 

A. W. Peabody, Control of pipeline corrosion, Second edition, published by National Association of Corrosion Engineers, Houston, Texas, 2001. 

Stress Corrosion Cracking One of the serious forms of pipeline corrosion is see. This form of corrosion consists of brittle fracture of a normally ductile metal by the conjoint action of a specific corrosive environment and a tensile stress. In the case of underground pipelines, see affects the external surface of the pipe, which is exposed to soil/ground water at locations where the coating is disbonded. 

E.P. Marshall, E.G. Peattie, Pipeline Corrosion and Cathodic Protection, third ed.. Gulf Professional Publishing, Woburn, MA, 1995. 

K. Bethime, W.H. Hartt, Applicability of the slope parameter method to the design of cathodic protection systems for marine pipelines. Corrosion 57 (2001) 78—83. 

Table 5 shows the risk level standards. The results indicate that 8 pipeline should be replaced partially or wholly because of its high risk level and severe pipeline corrosion 6 pipeline should be provided with regular inspection with an interval of about one and a half years, and its anti-corrosion wall should be thickened The rest 6 pipelines are at a low risk level, thus their test interval can be extended with regular inspection and maintenance (Table 6). 

Gartland PO, Drugli JM. Methods for evaluation and prevention of loeal and galvanie eorrosion in chlorinated seawater pipelines. Corrosion/92, Paper No 408, NACE, Houston, Texas, 1992. 

This may seem counter-intuitive, but in the case of high-sulfur content crude oils, pipeline corrosion is reduced when the oil is held away from the walls of the pipe, as is the case when O/W emulsion is employed. 

Lawson K (2005). Pipeline corrosion risk analysis—an assessment of deterministic and probabilistic methods. Anti-Corrosion Methods and Materials, vol. 52, pp. 3-10. 

The de Waard-Milliams model is a well-known modeH - used in industry (such as subsea pipeline corrosion) to predict corrosion, and it is the cornerstone of commercially available corrosion prediction software packages such as Cassandra. Despite its applicability in industry, a significant disadvantage of this model is that it does not consider MIC. In 2002, a NACE paper was published in which the described models were related to various mechanisms from sweet corrosion, sour corrosion, and organic acid corrosion to oxygen corrosion and MIC. Obviously, it is the model describing MIC that concerns us here. 

The schematic of pipeline corrosion can be represented by the diagram shown in Figure 8.1. 

Icing can occur in cold climates as well as at higher temperatures due to a fast-changing pressure such as in valves, where the pressure drop causes the natural gas to cool down. Cooling can make the moisture condense and even freeze, resulting in disruptions to the natural gas supply. The most common way to dry natural gas is to use glycol to separate the gas from the water. The gas is then either compressed for delivery via the pipeline or liquefied in a tank for delivery by other transportation methods. In pipeline transmission, the gas must be dry to avoid pipeline corrosion and formation of hydrates, as well as icing of valves [5]. 

Marsh J., Dnncan R, Richardson M. (2009), Pipeline Corrosion and Integrity Management— Experience from Eorties Field (Paper No. 09109), Honston, TX NACE International. 

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