Friday, January 23, 2015

Detection of Corrosion Under Insulation (CUI) and Blockages on Piping System Using Profiler System

CUI (Corrosion Under Insulation) has always been a challenge for plant operators, quality assurance/reliability engineers and equipment owners. It is hard to identify the problem until it has become an emergency situation, often leading to unit shut downs or even the whole facility shut down for emergency repairs.
As per industry statistics, next to leakages in flanged joints, the highest incidents of piping failure in process industry is caused due to corrosion in pipe, especially under insulation.

How CUI is Caused

An insulated piece of equipment can have trapped moisture by two means: moisture can become trapped due to cyclic equipment and condensation forming and being trapped under insulation. The second and more common reason is rain/ snow. Rainwater or water from melting snow will eventually enter weak points in the system and pour onto the surface under insulation. The difference when compared to a stack is that the water gets trapped because of the insulation and is not allowed to escape.
Thermal shock can also be a significant cause of CUI. Thermal shock is categorized by a dramatic rise or fall in the temperature of the equipment. Thermal shock may occur when a unit is turned on or off, during the normal cyclic conditions the unit may exhibit, or when the steel is exposed to water that has penetrated the jacketing.

Challenges in Inspection

CUI is difficult to find because the insulation covers the corrosion problem until it is too late. It is expensive to remove the insulation, inspect and then reinstate the insulation after inspection. Inspection of the covered areas without removing the coverings reduces the cost of carrying out an inspection. Therefore the development of non-destructive testing methods to detect corrosion in the above situations is therefore a major benefit to the industry. And same or worse is the case with erosion, especially when it happens at unexpected locations most often due to unusual operating conditions or turbulent flow in pipe lines and a variety of other reasons. And if this erosion is in an insulated line, the problem is multiplied many folds.

There are a number of methods used today to inspect for corrosion under insulation. The most common and straightforward way to inspect for corrosion under insulation is to cut plugs in the insulation that can be removed to allow for ultrasonic testing. The other commonly used methods are profile radiography, and complete insulation removal. More advanced methods now available includes real-time X-ray and low Intensity X-ray Imaging.

The Ultrasonic Thickness spot readings and profile radiography gives accurate values of remaining wall thickness but UT readings require the insulation to be removed and proper surface preparation. However, many times plugs removed for UT thickness gauging can itself be the source of moisture leakage. The main problem with this technique is that corrosion under insulation tends to be localized and unless the inspection plug is positioned in the right spot, the sites of corrosion can be missed. Radiography is time consuming and requires cordoning off the areas to be inspected. Both these techniques are reliable and economical only if you know the exact location of erosion and or corrosion, which is almost impossible.

CUI and erosion are mostly localised and often inspection results can be misleading as area as close as a few millimetres from corroded areas can be with normal thickness values.Tangential X ray, a relatively new technique shows the outer surface of the pipe but gives little information about the wall thickness or any erosion from inside.


Monday, January 19, 2015

Five important questions company Board members should be asking their senior executives

So often, companies reflect on how they should have run an intelligent pig earlier than they did, or opened up pipelines for direct internal visual inspection, or indeed stripped away external insulation, or dug up sections of buried lines, all to get a better understanding of what was actually happening at the time. This embodies the challenge of managing the risk of corrosion of pipelines and facilities where the steel surfaces are not accessible in normal operations. There seems to be a strong case for critical pipelines having short stretches of similar pipework in parallel, so that without interrupting operations this type of larger-scale sampling examination can be undertaken. Returning to the motoring analogy, it is like having two lanes for one particular direction of flow in certain places, where you occasionally close down one for detailed examination

There are five important questions company Board members should be asking their senior executives, and which investors and analysts, in turn, should be asking these Boards:

• What is your corrosion management process? 
• What has been your experience of corrosion during the last twenty years, what were the outcomes, and how were lessons learned disseminated? 
• How does information flow from readings taken on site by technicians, through to analysis and decision-making at senior management level? 
• What is your ‘corrosion model’ for predicting where damage might occur, and how often and in what way is this challenged and verified? 
• How does all this compare with international best practice? 

Many on the receiving end of such questions will feel uncomfortable, because corrosion is not on their radar screens. This has to change. The future will need to address improved handling of data and problem-solving, new materials, corrosion resistant surfaces and linings, and better understanding and inhibition of corrosion mechanisms throughout the oil supply chain. That will take good management……..and clever chemistry! 


Wednesday, January 14, 2015


Corrosion may seem an unexciting subject, but international and state oil companies now need to place much higher priority on both the technology and management of its causes, monitoring its effects, controlling its various outcomes and undertaking remedial work. Extraordinarily for its potential consequences, it is one of the few phenomena where widely-used inspection techniques remain out of step with the reality of the chemical processes involved. 

Companies unwilling to address this will have both their reputation and value compromised. During the last twenty years within the UK oil industry alone, there have been several major corrosion-related shutdowns of facilities and pipelines that have each cost hundreds of millions of pounds to rectify. Prudhoe Bay will shortly join a global list that has already grown significantly with major repair projects initiated in Russia, India and the Middle East, all driven by problems with corrosion. 

How has this come about? 
Firstly, it is important to draw a distinction between internal and external corrosion. The former largely affects mature fields that are well past their primary production phase, where the initial expansion of fluids and gas below ground is sufficient to drive the flow of wells. Instead, in this later, secondary phase, large volumes of water (typically from the sea or a river) are injected into reservoirs to displace the oil, rather like a piston. With time, however, water migrates through the oil, so that wells eventually produce more than 90% water near the end of the field life. 

Through water separation in surface facilities, often assisted by chemicals known as de-emulsifiers, the water content of the oil transported by pipeline for shipment at a port can be reduced to just a few percent. Internal corrosion of the steel pipe is driven by the presence of this remaining water, oxygen dissolved in it, and sometimes other substances such as carbon dioxide and hydrogen sulphide. The last of these can be generated by sulphate-reducing bacteria that are inadvertently introduced into the reservoirs during water injection. Many of the facilities most vulnerable to corrosion, in general, are well past their notional 25-year design life. 

Corrosion is controlled routinely by both chemical and physical means. For example, oxygen is reduced during the water injection process, and biocides are also pumped into the reservoirs. A key step is the injection of corrosion inhibitor chemicals into the pipeline itself, and the use of emulsifiers to limit the separation of oil and water within the pipeline. Furthermore, to stop any settling of water at low points in the line, and also to clear sludge and wax, cylindrically-shaped mechanical ‘pigs’ with scrapers are sent down the pipeline (driven by the flow of oil), to be recovered with the collected debris at the downstream end. Monitoring the effectiveness of these steps is through a variety of techniques. These include the use of small steel discs, or coupons, set into the pipeline so that they are exposed to liquids inside. 

These can be removed periodically for inspection and measurement without disrupting operations. Another method has a small strip of wire carrying an electric current inserted into the oil flow. As this corrodes over time, its electrical resistance increases. For pipelines that are readily accessible to technicians, an ultrasonic probe placed on the outer surface will indicate the wall thickness of the pipe. Finally, by sampling the liquids and measuring the way the concentration of iron salts varies along the pipeline, the loss of metal from the inside surface can be estimated. Collectively, all these methods indicate how extensive corrosion might be, and corrective action can be taken to address this. 


Wednesday, January 7, 2015

The cost of corrosion exceeded $1 trillion in United States in 2013

With little fanfare, a significant milestone in the effect of corrosion on the U.S. economy occurred in 2013 when the total cost of corrosion in the US exceeds $1 trillion annually for the first time. In a widely-cited study (NACE Corrosion Costs Study) by the National Association of Corrosion Engineers, NACE, the direct cost of corrosion in the U.S. was estimated to equal $276 Billion in 1998, approximately 3.1 % of GDP. However, this estimate is incomplete and outdated.
Closer examination of the 1998 NACE corrosion study’s own analysis, along with a calculation of inflation since the report was produced,  indicates that total corrosion costs in the U.S. now exceed $1 trillion dollars a year, and probably exceeds $5 trillion annually around the world (assuming 6% of the GWP of 84.97 Trillion in 2012) . The indirect cost of corrosion of is estimated to be at least equal to the direct cost. In that case, the total cost of corrosion is $993 B in March 2013 and estimated to exceed $1 trillion June 2013 (based on estimates of GDP from
The infographic below illustrates the growth in corrosion costs and shows how large of a draw on our economy corrosion is.

Cost of Corrosion Estimate for 2013 by G2MT Labs


Friday, January 2, 2015

Pipeline Corrossion

Degradation of pipelines is the result of the persistent attack by the environment on pipeline materials (coatings, welds, pipe, etc.). Buried pipelines are located within ever changing environmental conditions that may lead to a corrosive environment. Factors that may prevent or contribute to the initiation and attack on buried pipelines include the following. Additional information can be obtained from the report published by the National Energy Board in 1996 entitled “Stress Corrosion Cracking on Canadian Oil and Gas Pipelines”.
Pipe Coatings Buried pipe is coated to offer protection from the surrounding environment. A breakdown in the coating will result in pipeline metal being exposed. The material used for coating pipes varied over the years as technology evolved. For example; in the 1940’s and 50’s coal tar, wax, and vinyl tape were used; in the 1960’s asphalts were used; and in the 1970’s to present day fusion bond epoxy was and is being used. Polyethylene tape and extruded polyethylene jacket material was also used from the early 1950’s to the present day.

Cathodic protectionThe introduction of an electrical current on a buried pipe such that the electrode potential of the buried pipe is lowered creates an environment where metal loss is reduced. Soil conditions, such as moisture content and mineralogy influence the effectiveness of the cathodic protection, as does the type of coating on the pipe. For example, pipe coated with polyethylene material is shielded from cathodic protection more than pipes coated with asphalts.

Soil conditionsSoil structure and conditions will not only impact the effectiveness of the cathodic protection but also may contribute to the creation of a corrosive environment. Factors such as soil type, drainage, temperature, CO2concentration, and electrical conductivity all contribute to the environment surrounding the pipe.
TemperatureThe temperature of the soil as well as the temperature of the pipe may create favorable conditions for attack on pipeline materials. Liquid and gas lines have slightly different operating temperature characteristics but both are still susceptible. For example, with gas pipelines both the pipe and surrounding ground can vary from a high of 40oC upon leaving the compressor station down to 5oC at distances from the station.

Stresses (residual and others)Stresses in the pipe may lead to premature degradation of the pipeline strength. Stresses acting on the pipe include:
  1. residual stress from the manufacturing process,
  2. external stress such as those incurred due to bending, welding, mechanical gouges, and corrosion, and
  3. secondary stresses due to soil settlement or movement.
Pipe pressureCorrosion, in particular cracking, is related to the pressures exerted on the pipe. As the pressures within the pipe are increased, the growth rates for cracks also increase. The circumferential stress (hoop stress) generated by the pipeline operating pressure is usually the highest stress component that exists.

Cyclic loading effectsConditions where the pipe is under cyclic loads may result in increased crack growth rates. Operating pressures for large diameter pipe can measure up to 8700kPa (1250psi). The pipeline pressure continually fluctuates due to loading and unloading of product and is influenced by pump activity. This applies to both gas and liquid lines but has greater influence in liquid systems.