Coatings: 'Uncoating' Corrosion
Dhirendra Singh, Market Manager Oil & Gas, Protective Coatings, Akzo Nobel India Ltd

Depletion of hydrocarbon reserves in shallow offshore fields has compelled E & P players to explore deeper in sea for satiating rise in demand in harsh and challenging environments. In hydrocarbon sector, infrastructure is immune to corrosion which needs to be protected. It can be avoided by creating a barrier layer of paint, a coating or lining, or a metallic lining between the material and media. This article gives insights into the technologies for coatings.

The period of easy location of oil and gas reserves is over. Continued demand and rapid depletion of existing oil fields are propelling the industry into deeper in sea and more hostile environments and in isolated locations, which are lacking required infrastructure. Along with the offshore oil and gas exploration; long distance deep-water oil and gas transportation is becoming an ever pervasive challenge. According to the US Geological Survey, the Arctic region may contain up to 90 billion barrels of oil and a significant portion of these reserves is thought to lie in the on- and off-shore areas of Russia. There is an increase in better demanding solutions to improve the performance and life cycle of underwater extraction equipment. New methods of extracting oil from the sea bed have required the use of floating oil platforms, which have their own complexities. Pipeline assets need long-term protection in demanding conditions where the costs of failure are extreme. Despite these challenges, the project schedule expectations are getting tighter than ever before.

All of the above mentioned conditions add to complexities in oil and gas process chain.

The total annual cost of corrosion in the oil and gas production industry is estimated to be USD 1.372 billion, broken down into USD 589 million in surface pipeline and facility costs, USD 463 million annually in downhole tubing expenses, and another USD 320 million in capital expenditures related to corrosion. As carbon steel is used for more than 80 per cent of plant requirements as it is cost efficient, but at the same time it requires efficient methods of corrosion control. The philosophy of corrosion control rests on three basic methods: Change in the material of construction for the specific application, reduction of the intensity of corrosive attack by modifications in corrosive media and, creating a barrier layer between the material and media to avoid the direct contact, the last one offer a cost effective solution in many of the situations. A barrier layer can be paint, a coating or lining, or a metallic lining. High performance coatings, as a method of combating corrosion, are economical and less expensive than opting for a costly material of construction.

Protecting Steel, particularly exposed to high temperatures creates most demanding situations faced by coatings, and coatings help delay the process in part of the areas of problem.

The exposure to heat could be in three areas, namely immersion (e.g. Knock Out drums, separators, vessels, steel or concrete tanks, sumps etc. where the operating temperatures or design temperatures can be up to 1850 C or even above) or secondary containment, insulated steel (Pipes, Valves, Tanks, Vessels, other equipments), and the fluctuating temperatures (as low as -1960 C in cr yogenic uses and as high as design temperature of 6500 c, sweating lines).

Immersion
Immersion conditions that coatings/lining need to encounter in immersion situations in oil and gas industry are getting increasingly demanding because of necessity of refineries to handle sour, heavier and dirtier crude in comparison to sweet crude that is relatively easier to handle from corrosion perspective.

Coatings and linings provide solutions to immersion in hydrocarbons from ambient temperatures up to 1850C (Flue gases up to temperature of 2200C operating or even higher temperatures). While Epoxy Novolacs have been found suitable to use in immersion temperature situations (up to 90 / 950C) when in contact with hydrocarbons; superior modifications like polycyclamines curing agents are used to handle immersion temperatures up to 1850C with success. Polycyclamine curing agents based novolac epoxies have also been accepted and used successfully on buried pipelines at high temperatures, with and without cathodic protection. Areas like effluent treatment plants or alkylation plant area which handle chemicals and can have variation in pH as high as 1 to 13 with or without elevated temperatures in the range of 60 - 90 Deg C require Vinyl Ester technology or hybrid polymers to be used in the thicknesses ranging from 1 mm to 3 mm to provide long term solutions.

Owners and specifiers both, however, need to be careful in selection of the technologies and product. Generic selection of products tends to go wrong seriously in these cases unless individual product performance is looked into thoroughly. It is, sometimes not possible to simulate the harsh exposure conditions that linings have to encounter in oil and gas industry using simple standards such as ISO 2812 as these may not give a true representation of field performance. It is necessary to have a full understanding of the conditions and how these relate to performance testing and often it is necessary to interpret results of long term performance testing taking into consideration proven field exposure.

Corrosion Under Insulation
Coating systems applied under insulation are required not only to resist high operating temperatures (which are often cyclic) but also to provide corrosion protection. Corrosion under insulation (CUI) is a major problem in the refining and petrochemical industry, with effects often hidden from view and not discovered until it is too late. Corrosion is not a significant problem when a metal surface remains hot and dry. But in practice, hot and dry surfaces are difficult to achieve if temperatures cycle is below 1500C; a condition in which condensation may get created. Areas can often operate below process temperatures (which can vary) due to shut down or intermittent use of equipment, and it is not uncommon for insulation to be damaged, providing a potential pathway for moisture ingress. It has been reported that the risk of CUI rises significantly after 510 years of service in a plant, and that an average 60 per cent of all insulation in service for 10 years or more will contain corrosion-inducing moisture. If left unchecked, CUI can result in localised corrosion and leakage from pipes and vessels. If such equipment is operating under high pressure, the potential for a catastrophic failure poses a real threat.

NACE RP0198-2004, "The Control Corrosion Under Thermal Insulation and Fireproofing Materials-A Systems Approach," is a standard recommended practice developed by NACE and is intended for use by corrosion control personnel and others concerned with CUI of piping and other plant equipment. This standard details the current technology and industr y practices for mitigating corrosion under insulation via a systems approach; the standard refers to 3 different technologies: Epoxy/Epoxy Phenolic or Novolac, modified silicone and siloxanes.

New Technology developments for handling CUI include flexible polymers, which can provide both corrosion and heat resistance in wet and dry insulation situation. New generation Cold sprayed aluminum technology and use of inert polymers in comparison to traditional high-temperature coating systems provides superior performance and long service life while at the same time providing alternate to thermally sprayed Aluminum.

Thermal Cycling
Thermal cycling and thermal shock in particular, presents exceptional challenges to coatings. Severe temperature gradients often cause steel and its coating to contract at different rates, creating huge stresses within the coating film, which, when accompanied by insufficient flexibility, can result in premature coating failure. Rapid cooling and reheating may produce condensation under insulation which, through the process of evaporation, may deposit salt residues on the vessel surface, creating an extremely aggressive environment. Water ingress and the resultant wet insulation can lead to hot, wet, and humid conditions that many high-temperature coatings struggle to withstand.

A number of technologies have been developed by coating industry e.g. Epoxy siloxanes, which work to the upper limit of 3000C - 4000C in situations not encountering thermal shocks. The technologies used in such end uses include internally flexibilised epoxies, epoxy phenolics and inorganic copolymers. One of the latest developments in coatings are Titanium modified inorganic copolymers for handling high temperatures with thermal shock and fluctuations, both for cryogenic temperatures on the colder side and high temperatures up to 6500C. The additional benefit from this technology is significantly reduced complexity during project stage, as a single product can go in different temperatures.

In addition to the above there are developments to help industry in handling unique situations, examples being temperature indicating paints already used for visual identification of weak spots in refractory in secondary reformers , Epoxy syntactic foams that work as insulation, used especially in LNG application to avoid possible steel embrittlement in case of LNG spillage and similar application.

While polymer coatings and linings cannot solve all the corrosion problems, developments of polymers, coatings and lining technology has been able to solve many of the serious problems and challenges faced by oil and gas Industry, providing cost effective solutions, reducing the frequency of shut downs and enhancing the integrity of assets.