Technical Presentations at the July 2013 Meeting

1.1   High Strength Alloys in the Presence of CP Subsea and the Requirements for Preventing Hydrogen Cracking’, Charlie Barraclough, Commtech Associates

The first impact of CP on high strength metallic materials is evidently that assuming it is done properly it stops them corroding.  It may not be obvious that CP is needed, but many corrosion resistant materials used are not corrosion resistant when hot – and the temperature of subsea risers and pipelines and piping may be 100°C or more. At these temperatures 13Cr, 316, and 25Cr stainless steels are not corrosion resistant to seawater. 

The second impact on the materials is that the CP releases Hydrogen into the metal. This may not be a good thing if the metal has the wrong structure or is too hard or is highly stressed. 

The third impact on the metal is that there is usually a CP earthing or bonding cable which has to be attached, and this is usually welded onto the structure or component, which in turn affects the local stresses. 

This discussion paper looked at the effect the Hydrogen and welding may have on the metal; cracking may ensue and the ways of avoiding this were discussed. 

The Hydrogen atom and the Iron lattice were briefly introduced, as these are fundamental to the understanding of Hydrogen damage. The diffusion of Hydrogen and the crystal structure largely determine the onset of embrittlement. 

The various forms of Hydrogen damage in metals and metallic products were summarised. Many corrosion engineers will be aware of sulphide stress cracking and HIC. Welding engineers recognise heat-affected zone cracking, chevron cracking and lamellar tearing. Metallurgists are familiar with brittle failure caused by hydrides, acidic corrosion, pickling and electroplating. Refinery operators are aware of the problem of Hydrogen and methane blistering in Hydrogen service  All these are caused by Hydrogen. 

The particular types of steel and alloys which are susceptible to Hydrogen cracking were discussed. Basically, tough, soft austenitic alloys are generally less susceptible and harder, less ductile ferritic alloys are generally more susceptible; but there are special cases as were discussed - delta ferrite in Alloy 718 and graphite in Alloy K500. Duplex alloys have both a store of Hydrogen in the austenite phase and sensitive material in the ferrite phase. Martensitic alloys are the most sensitive. 

The roles of stress, strain, shape, strength, hardness, toughness, structure and composition were reviewed. At high stress Hydrogen is sucked into the lattice at the point of highest strain, and this prevents local deformation accommodating the local stress.  

The history of Hydrogen damage associated with subsea cathodic protection was related. We started with bolts for ships and other marine structures, continued with high strength steel used in jack-ups, next considered failures in piping and pipelines at local stress concentrations which are within code, then look at failures at anode attachments and finally considered welds, and the avoidance of high Carbon heat affected zones and fusion line cracking in Nickel alloys.  

The current state of understanding of mechanisms for avoiding Hydrogen cracking in cathodically protected components was proposed. Attention to metal processing, design detailing, the use of high integrity coating systems, the avoidance of anode connections and the avoidance of highly negative CP potentials were discussed. 

In conclusion, the use of highly stressed, highly strained, high strength, hard materials subsea is limited by cathodic protection. In general such materials should be avoided; however that is not always possible: where they must be used, coating, careful design, notch avoidance, avoidance of welding, metallurgical controls and CP restrictions must be implemented.  

It should be noted that the DNV RP F-112 criteria allow 80% of yield at stress raisers where austenite spacing is less than 30μ; but only 0.85 x 0.8 (68%) when the austenite spacing is not certain or the grain flow direction is not certain. In castings and heavy forgings austenite spacing and grain flow direction can not be guaranteed, so this should be assumed to permit only 68%.   

This limitation may not be as disadvantageous as commonly thought, since in many cases weight saving is not a primary objective. In this case the components may be deliberately oversized to reduce global stresses, and generously smooth section changes applied to reduce local stresses.   

For subsea (and onshore buried) high pressure, high temperature applications there remains a challenge. These systems are at the limit of available cross-section already, and the need for higher strength has already reached the hardness limits associated with CP Hydrogen cracking. Innovative design solutions may be required.    

To finish, examples were given of work planned to avoid CP HISC. This included a 22Cr duplex manifold constructed of HIP’d tees welded together. There were no set on branches. All the tees and all the hub connectors were subject to FEA and specially machined with large radius changes of section to minimise stress. All the valves were subject to FEA and had carefully rounded radii at the connections. The whole manifold was blasted and polychloroprene coated up to the connector contact points. The manifold was installed into the structure without welded attachments. We can see anodes on the structure but not on the piping. All the valves and interconnecting pipework were blasted and coated with GFVE and SPU. The manifold was bonded to the structure via mechanical connectors and Copper cable. 

Then a 13Cr flowline spool example was shown. The welds were in 25Cr post weld heat treated to prevent Hydrogen cracking of the HAZ. To prevent embrittlement of the 25Cr weld metal the heat treatment was terminated after 5 minutes by water quenching, using the same Copper coil as for heat treating. The welds between bends and pipe and hubs were tapered 1:8 (normally 1:3 or 1:4) to prevent stress concentration at the welds. The 13Cr pipe was three-layer-polypropylene coated. The field joints were coated with FBE and the injection moulded with polypropylene; shrink wrap or tape winding is NOT sufficient for these materials. There were no anodes attached to these pipe spools, which were designed to pick up CP from the manifold structure to which they were attached. 

[A pdf version of this presentation has kindly been provided and is available to members from the Secretariat]. 

1.2   Microbially Influenced Corrosion in both Oil Lubricated and Sea Water Lubricated Stern Tube Systems’, Graham Hill, ECHA Microbiology

The presentation described the author’s investigation of microbially influenced corrosion (MIC) in ship’s stern tube systems.  A background to MIC was provided with a particular focus on the mechanisms associated with microbially generated acids, establishment of oxygen gradients in biofilms and the corrosive products of microbial sulphate reduction and sulphur oxidation.  The author described his approach to investigating MIC in the field.  When establishing whether microorganisms have been involved in an observed corrosion incident, it is important to consider the location of corrosion damage, the visual characteristics of corrosion and other visual indicators, the chemistry of corrosion deposits, the availability of nutrients for microbial growth, the rate of corrosion, the numbers of known corrosion causing microorganisms and the pH and REDOX potential of water closely associated with the corrosion site.  

This approach was illustrated in the investigation of two incidents of corrosion in stern tubes, both in relatively new vessels.  In the first case, a twin-screw VLCC with sea water lubricated stern tube bearings, dramatic pitting corrosion was observed in the epoxy coated steel stern tubes and their forward flanges.  Investigation concluded complete microbial sulphur cycling was occurring with consequent generation of corrosive iron sulphide deposits by Sulphate Reducing Bacteria (SRB) and subsequent conversion of sulphide to sulphuric acid by Sulphur Oxidising Bacteria (SOB).  Corrosion of welds on the aft end of the stern tubes allowed penetration of water and microbial activity between the stern tube and the stern frame with development of highly acidic (<pH2) conditions.  Corrosion and failure of K-Monel forward seal springs was also observed, in probability due to oxygen gradients established under extensive macro and microbiological fouling.  The phosphor bronze forward seal housings were also corroded with apparent de-alloying.  The vessel is one of several built at the same shipyard which have suffered similar corrosion problems and consequent dry-docking for repairs.  Early indications are that conversion to a closed loop fresh water system on one vessel may have resolved the corrosion issues.    

In the second case, a single screw LNG carrier with an oil lubricated stern tube, gross fungal contamination of the lubricating oil occurred with resultant fouling and clogging of the stern tube, oil tanks, oil lines and the lub oil cooler.  Fungal biofilms developed on the oil side of the heat exchanger plates of the cooler and also on intermediate areas of the tail shaft between bearings.  Microbial generation of organic acids, and possibly also establishment of oxygen gradients, within these biofilms is believed to have been the principle cause of pitting and etching corrosion.  The extensive fungal growth is believed to have resulted from contamination of the oil system by microorganisms and microbial nutrients during the build.  Extensive re-machining of the tailshaft and replacement of perforated heat exchanger plates was required during an extensive dry-docking. 

[ECHA Microbiology Ltd., Unit 22&23, Willowbrook Technology Park, Llandogo Road, Cardiff, CF3 0EF, WALES, UK  [email protected]] 

[A pdf version of this presentation has kindly been provided and is available to members from the Secretariat]. 


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4.1  Developments (over 25yrs) and Current Practices in Metal Sprayed Coating for Corrosion Protection’, Terry Lester, Metallisation

After an introduction of Metallisation and the Thermal Spraying process, Dr. Lester described the critical differences between spraying and other corrosion protection coating methods, clarifying the correct requirements for preparation, execution and post treatment of the coating for various applications.  Following an extensive showing of field applications he described the state of the art as it was 25 years ago and as it is now, firstly in terms of equipment capabilities and secondly in terms of coating specifications used.  

He showed that there was a remarkable similarity between coatings applied nowadays and at the beginning of the period.  However in the interim, well intentioned excursions from previous practice had led to unforeseen issues some of which could have been predicted.  In particular the application of inappropriate sealers and excessively thick paint layers caused extreme local corrosion after a relatively short period especially in areas of very high chloride concentration.  This was due to the creation and entrapment of unstable aluminium chloride which decomposed to produce hydrochloric acid trapped between the steel and the thick paint layer, dissolving the aluminium and corroding the steel. 

Several new applications such as coatings for Corrosion Under Insulation (CUI) and coatings for wind turbines were presented as well as new spraying tools to improve the ease of applying coatings in difficult access areas.  The benefits in both cost and quality of automation were shown together with a short film of a start of the art fully automated facility for coating wind turbine segments. 

Finally many new standards had been created in the last twenty five years to improve the reliability of design coating specification and coating execution.

4.2     Corrosion Control and Materials Selection for Optimized Oil and Gas Asset Life’, Janardhan Saithala, GL Noble Denton

Corrosion is a constant threat for oil and gas assets which have to be operated in hostile marine environments and frequently transport and process corrosive fluids.  Ineffective corrosion control and inappropriate materials selection in corrosive oil and gas environments can cause premature material failure, which would not only lead to containment and production loss, but could also endanger health, safety and environment.  As seen in recent history, the economic, social or ecological consequences of such failures can be significant. 

Using appropriate materials and effective corrosion control measures can achieve optimised asset life while preventing premature materials failure in the oil and gas industry.  This necessitates fully understanding of the probable corrosion threats present in the field development, careful materials selection and effective corrosion control measures to be implemented from the earliest stages of design and construction. 

Effective corrosion control measures can ensure that the integrity of structures, process and utility equipment to be maintain throughout the life of the field or until a scheduled replacement/maintenance interval. 

Appropriate materials selection involves evaluating and balancing properties of corrosion resistance as well as strength, ductility, fabricability, availability, and cost of the materials. 

GL Noble Denton have many years of experience in effective corrosion control and appropriate materials selection for optimised oil and gas asset life. In this presentation, best practices to be employed in selecting appropriate materials and developing effective corrosion control measures are presented in accordance with the relevant international and industrial codes and standards.


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