Technical Presentations at the April 2014 Meeting

1.1  ‘Corrosion Management of Duplex Stainless Steel Gas Flow Lines’, Janardhan Saithala, DNV GL

Onshore gas production facilities commonly consist of network of flow lines feeding the gas inlet manifold before processing. A number of operators use duplex stainless steel (DSS) as one of the material of construction (MOC) for gas flow lines due to their good corrosion resistance which should avoid extensive maintenance and provide high availability of gas production. However DSS can still be susceptible to internal and external corrosion threats in both surface and buried environments. The threat of corrosion can be effectively managed if DSS flow lines are operating within integrity operating window (IOW) and the material limits are clearly understood. For these reasons effective corrosion management of gas flow lines is one of the core requirements in maintaining the integrity of gas assets and extending their period of operation beyond their design life. This presentation presented a methodology for corrosion management of DSS flow line installations. This presentation also discussed flow lines preservation strategy during the long periods of well shutdowns, and threats associated with stray current interference.

1.2 ‘Corrosion Challenges of Ageing Offshore Assets’, Pat Stokes, MACAW Engineering Ltd

In a maturing market, particularly the North Sea, to manage the integrity of ageing assets operating beyond their design life proactive corrosion management is essential. Ageing is not about how old your equipment is; it’s about what you know about its condition, and how it’s changing over time. Impacts of corrosion on ageing assets can be significant in terms of safety, production and the environment. In terms of where, when, why corrosion occurs and what can be done to prevent corrosion these are generally well understood. Corrosion awareness in terms of involving appropriate personnel, understanding, mitigating and maintenance activities has also improved in recent years.

Traditionally topsides process plant, subsea pipelines and onshore terminals have been subjected to individual corrosion management schemes. An holistic approach that brings the corrosion management of these individual components into an integrated Corrosion Management System (CMS) has been developed for a variety of ageing offshore assets.

The CMS comprises a Corrosion Control Scheme (CCS), a Topsides Risk Based Inspection (RBI) scheme, a Corrosion Risk Assessment (CRA) and a Pipeline Risk Assessment (PRA).

The objectives of this integrated CMS process are to:

• Proactively identify all corrosion threats and define related risk
• Define mitigation controls as necessary and ensure implementation
• Ensure mitigation controls are effective
• Establish and implement corrective action as necessary


The overall corrosion management strategy is implemented by the CCS for a specific production asset which identifies the corrosion threats. It establishes the control and mitigation procedures required to mitigate internal and external corrosion on topsides process plant, subsea pipelines and related subsea components. The degradation mechanisms, controls and mitigation procedures are mirrored in the other CMS components. The future inspection programme for topsides process plant is driven by the RBI, whilst the CRA and PRA drive the future inspection and monitoring regimes for subsea pipelines. Results from these components are fed back into any review and upgrade of the CCS.

A CMS has been developed and implemented that meets the following objectives:

• A transparent and auditable decision making process
• Proactively identifies corrosion threats and defines related tasks
• Defines mitigation controls as necessary and manages implementation and effectiveness
• Defines inspection and monitoring regimes to assess asset condition
• Establishes and implements corrective actions as necessary
• An integrated scheme such that changes in one component are mirrored in the others.


Overall there is good cross industry knowledge sharing, robust and mature CRA, RBI and CMS systems. However more focus is required on keeping equipment lists up to date, deeper audits of CRAs, RBIs and CMSs. Audits on the implementation of CMSs and the accuracy of inspection data is also required.  

[pat.stokes@macawengineering.com]


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1.3   ‘Effect of Service Conditions on Seawater Corrosion Risk = Influence of Corrosion Potential and Cathodic Efficiency’, Nicolas Larché, Institut de la Corrosion, France

Stainless steels are widely used for different applications in seawater in the oil and gas and desalination industries. The present work aims at reporting Corrosion Potential and Cathodic Efficiency of different stainless steel grades as a function of environmental parameters. The tested alloys were described, and the two exposure sites (France and Singapore). The results were then discussed with respect to temperature, dissolved oxygen, chlorination and temperate v tropical location.

Service conditions (temperature, biofouling, oxygen content, seawater treatment) and the actual crevice geometry (roughness, gaskets, loads) must be carefully considered since each of these parameters may significantly affect the corrosion susceptibility of stainless steel or the galvanic corrosion of connected alloys. A better understanding of the parameters influencing the corrosion of stainless steel is gained, which allows a safer use of stainless steels for seawater applications and the establishment of seawater corrosion engineering diagrams. Alternative stainless steel grades might be used for applications in which superduplex 2507 may be “borderline” (UNS S31266, S32707, S33207…)

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

3.1    'Internal Cathodic Protection of Offshore Sea Water Pump Caissons’, Robin Jacob, CP Consultancy & Brian Wyatt, Corrosion Control

There have been reports of corrosion damage to caissons for lift pumps, both for cooling/process/injection water and for fire water pumps for offshore oil and gas production facilities. Such corrosion problems appear to be endemic across many operators.

Two parallel studies have been undertaken in respect of sea water lift pumps (cooling/process/injection) and fire water lift pumps for a facility that had detected significant but not structurally threatening corrosion of caissons in which the pump strings had been fitted with galvanic anodes intended to prevent such corrosion.

Data from these studies, including external CP data, summaries of internal and external inspection data and modelling of new internal galvanic anode CP performance will be presented.

The study has derived some significant conclusions:

1. It is possible to predict the maximum corrosion hole size in a caisson in which the internal CP system is not functional and the external CP system is functional. The prediction is supported by experience.

2. Caisson internal corrosion rates due to galvanic couples between CRA pump columns and carbon steel caissons can be well predicted by mathematical modelling, the outputs are close to real experience

3. Simple but competently executed galvanic anode CP designs for pump strings within caissons are capable of delivering good levels of protection to the caisson internals. Protection may extend deeper below the pump string than is typically presumed. These simply designed systems may not deliver their intended lives

4. There is doubt that galvanic anode systems are always adequately installed; some may never be electrically connected to the pump string and thus can never function

5. There appears to be little understanding of the function of CP within the pump manufacturing and refurbishing vendors. This, with a procurement process that generally dictates that the pump vendors/refurbishers purchase the designs and anodes from third party specialist designer/manufacturers, could lead to cost pressured designs that are less than ideal or to competent designs delivering less than competent protection due to poor installation. There is inadequate liaison or understanding between the pump and CP companies. These appear to be current and historical issues. It is considered that many systems presently installed may not be functioning at all and most are not monitored for their internal CP performance

6. The operating and planned maintenance regimes for the pumps may not be consistent with the design life of the CP systems or the coatings and linings that may be in place on the CRA pump columns and generally are in pace on the carbon steel caisson internals

7. There is considerable merit in full factory assembly trials for the pump column with the CP system installed. This should be inspected by the CP designer or other CP specialist to ensure that installation is fully understood and that it is likely to be robust for the life of the pump string CP system. It is imperative that the appropriate installation details are conveyed in adequate detail to the offshore pump installation team or it is possible that a well designed system will not function or will soon fail in service due to inadequate understanding by the installation team of critical issues for CP performance

8. Mathematical modelling appears able to optimise galvanic anode designs for this application and thus deliver a more secure performance and life for the CP system and the caisson. Importantly, even an apparently competent and rigorous CP design using conventional calculations was indicated to be incapable of delivering full cathodic protection for the full design life of the CP system and was significantly modified to reflect the model outputs before implementation. It is noted that there no applicable codes or Standards for the design of CP systems for pump caissons; the use of, for example, DNV RP B401 for this application is well beyond the defined scope of this document and beyond DNV’s intent; it would be naïve to use the default design parameters in this document for this purpose

9. There were significant issues and threats related to the use of super duplex stainless steels in conjunction with galvanic anode CP

10. There was a rapid learning curve for all involved in this project; these included the original CP designer/supplier, the pump refurbishment company, the oil/gas company Client team and CCAL as the corrosion and CP specialists. This learning occurred with goodwill and openness from all parties. The lessons learned are likely to be applicable widely in the offshore sector.

3.2   ‘Under Pressure; Consequences of Aqueous Corrosion in the UK Fleet of Power Plant’, Paul James, E.ON Technologies (Ratcliffe) Ltd

Superficially at least, any connections between the land based fleet of power plant and equipment operated in marine environments would seem tenuous and confined to the active recruitment by the newly nationalised power industry of personnel released from the navy during the immediate post war period.

However, the presentation sought to highlight shared concerns across the both industries regarding the cause and consequences of component failure.

The presentation initially took the audience through the evolution of the steam boiler, from Hero’s Eolipile, that entertained audiences in 50AD, to the modern era. This journey included the workhorse of the 18th century industrial revolution and its subsequent refinement through the next century in the pursuit of greater efficiency and concluding with the transition from the fire-tube to the water-tube boiler at the start of the 20th century to allow the construction of ever larger, safer and more efficient plant over the next 100-years. Despite the range of available boiler designs to accommodate fuel diversity, all involve the conversion of water to steam and all are vulnerable to tube leaks holding potential commercial and safety implications for the operator. These failure events derive from the exclusive and synergistic effects of the thermal, mechanical and chemical environments to which tubing is exposed during service, including the potential for aqueous corrosion from both the tube fireside and steam/water side. Complemented by a series of case histories to illustrate the potential consequences of such events, the presentation proceeded to briefly describe the key aqueous damage mechanisms experienced on power plant boilers:

• On-load corrosion, associated with the concentration of acidic or alkaline species on the tube waterside
• Stress corrosion cracking, requiring the synergistic interaction of stress and environment on a susceptible material
• Off-load, internal corrosion, generally associated with the development of oxygenated pools of condensate in steam tubing during off-load periods and having the potential to encourage secondary damage mechanisms such as fatigue related cracking
• Flow assisted corrosion, active within a narrow temperature window in aqueous systems with a low oxygen potential and augmented by acidic conditions
• External wet corrosion, affecting tubing and external pipework exposed to sustained moist environments, particularly under insulation
• Acid dew point corrosion arising where components exposed to flue gas are operating at temperatures below the dew point of sulphur or chlorine species.

In concluding the presentation, it was noted that not all tube failures are associated directly or indirectly with aqueous processes, but that, when implicated, the damage is often insidious, may have significant safety implications and be less amenable to routine condition monitoring that with other damage processes.

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