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Corrosion resistance – the facts

Published:  27 January, 2014

Corrosion can be a major problem in offshore oil & gas applications. Offshore Design & Engineering Europe spoke with Steve McBride, product sales manager Fluid Controls & Instrumentation, Parker Hannifin, and Jos de Kruijk, sales engineer Marine/Oil/Gas at Eaton Industries LP, about the reasons corrosion can occur, the materials that can best withstand such issues, and how the environmental conditions in the North Sea differ from wells built in other areas of the globe.

With the presence of extreme corrosive elements such as hydrogen sulphide, carbon dioxide, brine and a whole range of hazardous chemicals compounded by extreme temperatures and pressures, there are few more arduous environments than offshore. Therefore applications that are resistant to corrosion can make the difference between efficient long-term operation or increased downtime, unscheduled maintenance and lost production. At worst, equipment constructed of the wrong materials can lead to catastrophic failure and potential human, environmental and economic loss.

And aside from the need to shutdown plant or equipment to repair, replace or carry out preventative maintenance on corroded items, there are also issues that include expensive overdesign to compensate for anticipated corrosion, decreases in system efficiency and related failures of adjacent equipment to consider and contend with. Corrosion due to the presence of extreme corrosive elements can be classified under several headings:

Uniform corrosion – Sometimes also known as general corrosion sees a decrease in metal thickness per unit of time or uniform deposit of corrosion products on the surface of the metal.

Galvanic corrosion – results from contact between two different materials in a conducting, corrosive environment. Galvanic corrosion may result in the very rapid deterioration of the least resistant of the two materials leading to a fatal failure. Avoiding the mixing of different materials, for example on tubes and fittings or valves is the most common method of minimising the problem.

Crevice corrosion – is an electromechanical oxidation reduction process. It occurs within localised volumes of stagnant trapped solution trapped in pockets, corners or beneath a shield of some description. The corrosive process is greatly accelerated if chlorine, sulphide or bromide ions are present in the electrolyte solution. Crevice corrosion is considered far more dangerous than uniform corrosion as the rate at which it acts can be up to 100 times higher.

Pitting corrosion – is characterised by deep, narrow holes that can penetrate inwards extremely rapidly while the remainder of the surface stays intact. Perforation of a component can occur in a few days with no appreciable reduction in weight of the overall structure. Stainless steels are particularly sensitive to pitting corrosion in seawater environments.

Intergranular corrosion – progresses along the grain boundaries of an alloy and can result in the catastrophic failure of equipment, especially if tensile stress loads are present. Localised attack can occur while the rest of the material is completely unaffected. The presence of impurities in the boundaries or local enrichment or depletion of one or more alloying elements can be the catalyst for this type of corrosion.

Stress corrosion cracking – sees a combination of tensile loading and a corrosive medium causing the initiation of cracks and then their growth. Time to failure depends on specific application factors and can vary from just a few minutes to several years. Stress corrosion cracking is a very serious and permanent risk in many industrial applications where materials are often under mechanical loading for sustained periods or indeed permanently. In addition to selecting the correct materials, the risk of this type of corrosion can be avoided by stress relieving or annealing after fabrication of the assembly, avoiding surface machining stresses and controlling the corrosive environment.

North Sea environment

Steve McBride, product sales manager Fluid Controls & Instrumentation at Parker Hannifin, considers that, compared with oil & gas structures in certain other geographies well-populated by oil & gas activity, the North Sea region could be considered to be relatively shallow waters. “Oil & gas wells in the East and around South America to the West are particularly challenging areas where structures have had to go down deeper than in many other areas around the globe,” he said. “This can also result in working with particularly high pressures and with more corrosiveness. Someone said to me once that the North Sea is like a paddling pool by comparison.”

Jos de Kruijk, sales engineer Marine/Oil/Gas at Eaton Industries LP, agrees that, in general, the challenges with regard to corrosion are more severe in tropical waters as the temperature causes more water to evaporate from the ocean. And this, de Kruijk explains, leaves the ocean more saline. He makes the point that higher temperatures accelerate corrosion. “The more corrosion resistant a material, the higher will be the Critical Pitting Temperature (CPT) and Critical Crevice Temperatures (CCT),” he said, adding that Eatonite has CPT and CCT of 85+ degrees C. Specific challenges are, as suggested, especially around the low temperature. “Eaton place great emphasis on equipment reliability, including corrosion,” said de Kruijk. “For many years we have run an ongoing programme of developments in this area. We are also keen on improving energy efficiency and overall productivity, both issues that can be affected by corrosion.”

However, from a corrosion point of view, McBride stresses that North Sea wells encounter much the same challenges as those in hotter and deeper climes. According to McBride, one of the key challenges is ensuring that whatever parts and equipment are fitted they should last as long as possible before they need to be repaired, overhauled or replaced. He adds that it is therefore worth paying more for parts made of more resilient materials.

The materials

So, what are the most effective and reliable types of materials used in equipment – such as tubing, fittings, values, manifolds, hydraulic cylinders etc. – for offshore applications? McBride reflects that when North Sea oil & gas wells first began to be built back in the 1960s a material called 316 Stainless Steel seemed to be the answer to corrosion issues. “However eventually it was found that it wasn’t really stainless at all, although the material’s composition included approximately 2 to 3 per cent of molybdenum, which helps with corrosion protection,” he said.

Back in the early days 316 or 316L stainless steel, McBride points out that the material wasn’t as expensive as it is today, and people were understandably using the maximum amount of molybdenum to get the maximum corrosive ability out of it. “However as time has gone by companies have made equipment with 316 – still within the UNS No 31600 standard percentage range of Molybdenum but closer to 2 per cent than 3 per cent,” explained. “This scenario naturally led people to look towards sourcing something different.”

McBride adds that looking at some of the area platforms in the North Sea they are certainly blighted by corrosion. “Nevertheless, their owners are constantly looking at better ways of extending their lives,” he stressed. “We are therefore not only looking at new platforms and putting in new materials but are also looking at old platforms in order to best refurbish them by putting equipment made of the most corrosion resistant materials.”

For Golden Eagle in the North Sea, McBride points out that Nexen specified what is called 6Mo. “This material contains 6 per cent of Molybdenum, which gives it its extra corrosive resistant capabilities,” he said. “Nexen uses this as the base material. So things have moved on from the days of 316. A competitor material to 6Mo now also commonly used in the material construction of equipment used on North Sea wells is Super Duplex. Parker does provide some products in Super Duplex, however we mainly focus our attention on 6Mo.”

According to McBride, one of the main reasons for focusing mainly on 6Mo relates to the PREN (pitting resistance equivalent) number, which is a measurement of the corrosion resistance of stainless steel containing nickel. McBride explains that the PREN number is a little like CV calculations for flow rates. “So with the PREN number we are mainly concerned with the composition of the material, and there are certain national or international standards that it has to conform to. 6Mo has a minimum PREN number of 42, while Super Duplex has a minimum PREN number of 38. So the PREN number of 6Mo is higher but the material is also slightly harder. And if you look at the twin ferrule fitting there’s a certain amount of compression of the ferrules so you need to compensate for this. Super Duplex is slightly softer and 6Mo is slightly harder – so, on the basis of optimum corrosion resistance the majority of our customer’s requests for equipment are for 6Mo or better.”

McBride qualifies the above comments by pointing out that there are other applications where more Corrosion Resistant Alloys may need to be used, such as Titanium, Alloy 825 (Incolloy) or Alloy 625 (Inconel). “We offer parts in these materials as well, in addition to products made of other resilient materials such as Alloy 400 (Monel) and Alloy 276 (Hastelloy); but as a base material a lot of the new projects tend to be 6Mo or Super Duplex. he said. “In fact, we’ve won a considerable number of oil & gas projects with 6Mo in the North Sea; Golden Eagle being one, as well as GDF Suez as a Cygnus project – which is presently being built.”

According to de Kruijk, Duplex and Super Duplex stainless steels and Hastelloys are certainly well-proven. “Generally, Titanium has excellent corrosion resistance but is too expensive to be practical for large structures,” he said. “We have found that laser clad coatings offer superior performance in demanding offshore applications at a reasonable cost. We have developed a highly specialised laser clad coating for use on the rods of the hydraulic cylinders we supply, called Eatonite. From the patented base material, through a tightly controlled application process to the tested and documented product this provides the best end result.”

de Kruijk adds that extra-large (XL) hydraulic cylinder rods could be manufactured from solid Duplex stainless steel or even Titanium, but he points out that this approach is costly “A more economical and technically sound approach is to fabricate the XL cylinder rod from a high-strength, low alloy steel and then to laser clad the exterior with a corrosion resistant and wear resistant material, such as Eatonite,” he said. “This optimal approach takes advantage of the high strength steel base metal and the extreme corrosion resistance and wear resistance of the Eatonite. Laser clad Eatonite also offers high integrity and bond strength many times higher than competitive coatings like HVOF, High Velocity Oxy-Fuel Gas thermal spraying.”

Additionally, de Kruijk considers that new laser-clad coatings will offer the desired ‘triad properties’, the combination of extreme corrosion resistance, high abrasive wear resistance and anti-fouling resistance in a single coating. “Today’s materials Super Duplex stainless steel, Inconels, Ultimet, Hastelloy and Stellites cannot offer this combination of properties,” he said.

Equipment example

One commonly found piece of equipment found in offshore oil & gas is the twin ferrule type fitting, comprising a body, nut, back ferrule and a front ferrule. When the nut on a twin ferrule fitting is tightened onto the body the back ferrule this pushes onto the front ferrule. That front ferrule then compresses into the body of the fitting and the back ferrule grips the tube. The mechanics of this process provides a double seal. All well and good. However, here lies a good example of the need to put in place an effective corrosion-protection regime to avoid not just equipment failure but also health & safety issues. McBride points out that the back ferrule needs to be hardened to help it to grip onto the tubing more effectively. “This is an important process because it is this back ferrule that does most of the work under high pressures day in day out. Also, if that back ferrule for whatever reason starts to corrode then you’ve lost the integrity as well as the mechanical safety of the fitting.”

There are many different ways to harden these ferrules; they can be chrome plated or edge-hardened, for example. However, according to McBride, the problem with undertaking this hardening process is that the back ferrule’s corrosion-protected nature can sometimes be compromised. “If the part is work-hardened then the composition of the material surface can change,” he remarked. “If you look at some companies’ fittings you will see a brown stain coming away, and that brown stain is more often than not because of the back ferrule corroding. This can be dangerous when the fitting is used at high pressures. Parker’s process of Supercase-hardening the back ferrule best protects it against corrosion.”


And what of regulations/standards and other forms of materials and parts control related to coatings, materials and general issues concerning corrosion in the oil & gas industry? de Kruijk points out that many customers have banned the use of thermal sprayed ceramic coatings on direct acting riser tensioners. “As the deposition rate of laser cladding goes up and as costs come down, the use of HVOF coatings likely will fade out for many marine splash zone applications,” he said.

McBride explains that energy companies such as Statoil approve the foundries from where manufacturers such as Parker source the material from before they can be supplied and fitted in North Sea oil & gas installations. “So the industry has the quality of the mixing of materials fully policed,” he said. Also, for North Sea installations, among other regions, McBride points out that oil & gas well builders mainly insist on a European or North American source of those materials in order to best monitor the integrity of the material certification, among other reasons. He added that Parker has full Norsok M-650 approval for its 6Mo fittings and tubing.

For many of Parker’s current projects, the company is also seeing a requirement for PMI (positive material identification) testing for every product, or a percentage of the products, it supplies to the oil & gas industry. “Parker has one of these testing machines in Barnstable where we manufacture our fittings,” said McBride. “This machine can provide a breakdown of the total composition of the material. We find that certain EPCs (Engineering, Procurement, Construction companies) will say they want a 10 per cent PMI or 100 per cent PMI. This is considered to be the best methods to ensure the correct level of corrosion resistance for products used for a variety of different purposes on oil & gas wells.”

In summary, an awareness of the most corrosion-resistant materials and coatings can not only minimise costly downtime and maintenance or overhaul activity, but also improve health & safety standards as well as afford energy efficiency-related benefits.

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