Ask the Expert – Part 2

This month, the questions being answered by our corrosion technology experts relate to acid storage tank linings and the deployment of non-intrusive corrosion monitoring devises for pipelines and process pipework.

There are many types of non-intrusive devices for corrosion and erosion monitoring, and these do not normally form part of, or experience the pressure envelope, as they are merely attached to it to monitor underlying conditions such as high risk solids/flow erosion, e.g. unintended sand production in crude oil at reservoir start-ups. Many of these devices have been available for years using well-established technologies/principles of corrosion/erosion monitoring, such as Automated Ultrasonics. In recent times these technologies have been developed much further in the quality and accuracy of data provided so that they are often better than manual methods, and by improvements to power packs and to the transmission of collected data, (wireless or hard-wired links to process control panels with pre-set alarms). Modifications to make the equipment safe to deploy is hazardous areas, through independent certification such as ATEX (explosive atmospheres)and associated European Directives for controlling explosive atmosphere, have been made. Directive 99/92/EC, (also known as ‘ATEX 137’ or the ‘ATEX Workplace Directive’) on minimum requirements for improving the health and safety protection of workers potentially at risk from explosive atmospheres and Directive 94/9/EC (also known as ‘ATEX 95’ or ‘the ATEX Equipment Directive’) concerning equipment and protective systems intended for use in potentially explosive atmospheres. In the UK, the requirements of these Directives were put into effect through BIS (SI 1996/192), Equipment and Protective Systems Intended for Use in Potentially Explosive Atmospheres Regulations 1996.

Given the very wide choice and different specifications of equipment available now, how does one select the most suitable equipment for effective corrosion/erosion monitoring? AB

The answer to this, is to some extent in the question itself, as firstly, it is important to determine what level of monitoring is actually required (it’s criticality) and where that equipment is best located in service (in hazardous or non-hazardous zones) and accessibility for future maintenance, as many regulatory requirements and operator site specific standards must be met both at initial installation and for future maintenance of such equipment.

A key factor is operating temperature, and design modifications are usually required for sensors in constant contact with very hot surfaces. It may also be necessary to temporary remove thermal insulation from pipework and protective safety cages, for installation and to repair this afterwards to prevent water ingress.
If significant erosion of material is expected, sensors must also be correctly positioned to monitor key ‘impact points’ on bends, tees and other geometric configurations, and to be able to do this effectively. It is necessary to have a clear understanding of the internal flow rate and 
regime e.g. laminar or turbulent, as may be indicated by the Reynolds number (Re), which can be calculated by multiplying the fluid velocity by the internal pipe diameter and then dividing the result by the kinematic viscosity. The flow regime is influenced by the fluid properties, the flow conduit size and rates of each of the phases.

For internal corrosion degradation, the likely orientation of this damage must first be determined and the appropriate spacing of sensors specified in sufficient numbers to detect the expected deterioration mode, such as shallow or deep pitting, distributed or localised decay, bottom of line, top of line, etc.
Most sensors (magnetic or clamped) rely of having an associated power pack with the batteries typically lasting between 3-9 years according to the selected interval between measurements. It is very important that the measurement interval suits the type of data being collected, e.g. high frequency data gathering is required for well-commissioning activities where solids production is an expected risk.

Note that this equipment may be either of the relocatable/re-use type, when only temporary/short-term measurement is required, or of the more permanent types, perhaps installed more comprehensively with multiple sensors, e.g. for CUI, or other more intensive applications, even under water such as on subsea pipelines.
Non-intrusive devices provide additional monitoring possibilities where intrusive devices are not available. They are also extremely useful where intensive/regular measurement is required and avoid labour intensive (and often less accurate) manual data gathering methods. Compared to intrusive devices, they are more frequently of the automated type with data transmission to control rooms or using vendor installed software, or alternatively linked to the client’s systems. As with all such equipment however, the devices must be regularly checked/calibrated at site, so as to provide reliable data.

Consideration of all the above factors will greatly influence successful applications/outcomes in this growing area of the CM equipment market. ST
Readers can submit generic (not project specific) questions for possible inclusion in this column. Please email the editor at,

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