Subsea asset integrity is a growing challenge on the UK Continental Shelf and elsewhere, with each basin having its unique set of often complex demands. This applies to traditional oil and gas plant as well as the new generation of renewable energy structures. Matthew Kennedy looks at ways approach the challenge.
In the UK North Sea alone there are some 45,000km of pipeline, umbilicals and cables and more than 5000 subsea wellheads (source: Oil and Gas Authority). Challenges maintaining this infrastructure during operational life take the form of varied failure and deterioration mechanisms.
Fortunately, there is a multiplicity of inspection technologies and tools, extant, evolving and emerging, to help detect, measure and monitor anomalies. Many of those tools originated in the medical, nuclear and military sectors and have been successfully adapted to operate in the testing subsea environment.
The range of problems affecting subsea asset owners and operators, to stay on the right side of the regulator, is wide but fundamentally includes in-service material degradation, due to years of operation and harsh environmental conditions leading to fatigue, and different corrosion types.
Designers of subsea systems, such as pipelines, have engineered assets so that they meet their expected design life. This has been achieved typically by fabricating heavy wall pipes to accommodate internal operational wear and tear, together with coating systems to protect from external damage. Concrete weight coating and mats offer further protection and asset stabilization.
Physical access to plant, for inspection, should be a prime consideration for operators. Where internal access can be gained, free swimming pigging operations can be launched to perform cleaning and low to medium-resolution screening. Similarly, tethered tools can be deployed into rigid riser systems to facilitate high-resolution examination.
If internal access is not possible, external access might be achieved, via de-burial and weight coat and general fusion bonded epoxy (FBE) type coating removal, following which a range of techniques can then be considered for deployment. These include established techniques, such as eddy current, alternating current field measurement (ACFM) for detection of near and surface breaking component flaws, as well as electromagnetic transducer (EMAT) and long-range guided ultrasonics, for general pipe wall screening.
A new generation of inspection methods has also emerged, including some which, until recently, were for topside use only, but have been adapted for underwater deployment.
In addition, the remote deployment of subsea inspection tooling using remote operated vehicles and autonomous underwater vehicles is assisting both mature and new technology developments. Evolving capability in this area can dramatically decreases the cost of collecting valuable plant condition data and opens up the opportunity for asset monitoring in subsea factory scenarios, where inspection, repair and maintenance (IMR) tools can be parked on the seabed and activated when required (OE: October 2016 & September 2017).
With such a suite of options for inspection, the challenge becomes deciding what tool or methodology to apply. The specific nature of a given application (no two are ever quite the same) will quickly help generate a short-list of applicable techniques.
Final owner/operator selection is invariably based on; criticality of the test requirement, awareness and availability of the most appropriate technique and the economic case for proceeding.
For example, using what appears to be a compliant and economic solution to gather remaining thickness measurements on a pipeline by collecting single point ultrasonic measurements may tick the action box but may actually be a false economy. In practice a spread of high-resolution ultrasonic wall thickness maps are often necessary to perform meaningful assessment. This type of application has historically and justifiably been perceived as a costly option. However, with the advent of smaller, more efficient inspection tooling delivered by remote deployment systems the cost barrier for collecting this level of data has reduced significantly.
Pitfalls, such as using inappropriate techniques, generate inadequate data, which in turn raise more integrity questions than answers. It also diverts and reduces budget that could have been applied in gaining real insight into the asset condition.
For subsea inspection applications, the medium- to long-term objective is, as with topside plant, to have installed or local (seabed) based monitoring systems flagging up anomalies as they occur, relaying changing state information to shore in real-time.
In the short- to medium-term it is a case of a regulatory compliance through discriminatory selection of all available technologies and delivery systems, in order to get them to where they are needed as cost effectively as possible.
Matthew Kennedy is the CEO and co-founder of 1CSI, a newly established Aberdeen-based subsea integrity consultancy. Before that, he was subsea integrity manager at Oceaneering and prior to that held senior roles at AGR Field Operations. He studied at Durham University.
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