Risks and rewards: the importance of investment in subsea IMR

16 December 2014

Subsea equipment failure is bad news for everyone and everything concerned. Wood Group Kenny’s integrity management specialist Jason Strouse explains how effective risk assessment can be the difference between triumph and disaster.

Everyone and everything, from oil and gas operators to offshore personnel and the environment, benefits from avoiding subsea equipment failures. That's why the industry spends huge sums every year on inspection, maintenance and repair (IMR) programmes. Taking a more intelligent approach to IMR planning can also deliver lower risks and lower costs.

Rather than sticking to rigid service and inspection intervals, operators can use equipment condition, process and other field data, along with historic performance information on shared industry databases, to predict deterioration and intervene only when necessary. This optimised way of managing IMR is part of today's holistic, risk-based approach to integrity management for subsea and many other types of assets, on and offshore.

"In a large field, you might have billions of dollars' worth of equipment that you need to protect," says Jason Strouse, integrity management specialist at Wood Group Kenny. "Through integrity management, you are looking at preventing loss of containment and reliability that might cause damage to the asset, leaks to the immediate environment and risks to personnel.

"You need to look at everything from your emergency preparedness and system interfaces to safety barriers and fire protection."

SURF's up
Integrity management has an extremely broad remit, covering the systematic implementation of many different activities. The aim is to ensure that critical subsea, umbilical, riser and flowline (SURF) equipment and systems are properly designed, installed and maintained so that they remain fit for purpose for their lifetime.

Accurately calculating risk lies at the very heart of integrity management. To assess overall risk, operators and suppliers must consider all the possible equipment failure modes, their likelihood and the consequences.

For example, pipeline failure mechanisms include corrosion, flow restrictions and wall thickness, while dynamic systems, like risers, may suffer from accidental damage, or material fatigue. Often, there will be multiple issues potentially contributing to failure.

To assess the probability of failure in a pipeline, engineers must weigh up the effects of many critical parameters, including pressure, temperature, wall thickness, hydrate build-up, water cut, coatings, insulation and the types of fluids used and pipe materials. Uncertainty due to new technology, manufacturing defects and installation errors all feed into the calculations.

Each field will be different. High water cuts, or H2S, could cause swifter corrosion than predicted, or sand production might jam valves.

Resources like the OREDA reliability database help in the probability assessment, codifying years of learning about the integrity of different offshore systems under various conditions.

The aim is to ensure that subsea, umbilical, riser and flowline equipment and systems are properly designed, installed and maintained so they remain fit for purpose for their lifetime.

Industry standards and statutory requirements are typical constraints in the overall risk calculation. For example, in the North Sea, bodies such as the UK's HSE and BSI or Norway's NORSOK govern what is allowable in health and safety, lifting, control systems or subsea safety valve testing. Other local legislation will specify what, if anything, can be released into the environment.

Understanding the failure mechanisms and their likelihood then informs the monitoring, inspection, testing and analysis required, along with the operating procedures and IMR intervention needed to keep risks to an acceptable level.

"The whole point is to take action before things go bad," explains Strouse. "If you have a fully developed integrity management plan, you can mitigate those risks and do your best through IMR activity to respond, inspect and repair when you need to."

Risk business
Many operators still carry out subsea maintenance and inspection at fixed intervals but a risk-based inspection (RBI) approach is increasingly common. An evolution of condition-based monitoring, it looks forward, as well as back to historical data, to help plan subsea IMR in the context of failure risk.
"Once they have identified the risks and interpreted the data, they will chart them to show critical risks and lower risks," explains Strouse.

"Then they will apply ALARP (as low as reasonably practicable) principles to bring critical risk down to what we call the 'tolerable' regime. If we can bring them down further to an 'acceptable' level, then that's what we'll do, perhaps by IMR intervention."

ALARP arises from the fact that infinite time, effort and money could be spent on attempting to reduce a risk to zero. When the cost involved in reducing a risk further is grossly disproportionate to the benefit gained, a tolerable risk level must be decided upon.

At this point, qualitative judgement comes into play, as it does in deciding how to mitigate a risk like, for example, a thinning pipe wall rupturing. According to Strouse, some operators might change operating procedures to lower pressures, while others may inject more inhibitor to slow down the corrosion rate, or increase inspection frequency to be sure they know when it gets too fragile.

Where risks are deemed too high, equipment may have to be replaced, or redesigned, to be acceptable. "At some point, you will have to go in to cut out and replace the section or the whole flowline," says Strouse.

RBI techniques are intimately linked to component and system reliability calculations: how long does each piece of equipment have to last to protect an asset and the individuals working on it? That means that accurate data fed from installed sensors and gathered from IMR tools is vital for RBI to work effectively.

"We want to verify the exact state of the component. Is its condition a concern?" says Strouse. "If we have data on a pipeline that shows elevated levels of CO2, rather than just a visual inspection, we may try to pig it to see if we've had accelerated wall loss, pitting or corrosion. Accurate data helps bring those risks down below the tolerable or acceptable threshold."
Inspector calls
With that thickness data in hand and with experience of the correlation between elevated CO2 and corrosion limits, it's possible to calculate when the next inspection is needed. Next year, if the CO2 levels haven't changed, the IMR team may only run a general visual inspection and wait for another 12 months before pigging it again.

"It's a feedback loop: wash, rinse, repeat," says Strouse. "It's about being predictive, rather than reactive. With the RBI process, you might have a higher inspection rate after first oil, but reduce that over time."

As a production field ages, so the process conditions can change with the higher H2S or elevated water temperatures found in subsea systems. Operators must adjust integrity management and RBI programmes to take account of any differences and make sure they stay below the appropriate risk thresholds.

"Equipment might originally have been designed to handle only a small amount of H2S," says Strouse. "What must we do to recover and make the risk acceptable again?"

The net result is reduced costs for the same, or lower, level of risk. The savings come from fewer IMR interventions and from substituting simpler operations for more involved ones, which also reduces the spread of tools needed on IMR vessels. Continuous monitoring systems, such as electrical field mapping for corrosion, along with advanced IMR tools, are also helping cut costs and raise predictive accuracy.

"Instead of having to go down and do a UT [ultrasonic test], a PEC [pulse eddy current] inspection and an internal inspection, there may be a tool that does all of that from the outside," says Strouse. "Though they are still in their infancy, these sorts of 'CT scanning' tools are now starting to come online."

Newer techniques, such as guided wave testing and digital radiography, are particularly valuable for unpiggable flowlines. Though alternatives, like computational flow dynamics calculations, can be used to try to estimate wall thickness, external inspection or complete replacement have previously often been the only available options.

New technologies are part of the remit of the ongoing SURF IM Joint Industry Project. Steered by Wood Group Kenny, it has helped to enhance general understanding of best practice in subsea integrity management for its 12 participating operators.

The first two-year phase identified key failure mechanisms, investigated inspection and monitoring technologies and technology gaps, and developed new operating guidelines.

We are starting to see a lot more rotating equipment, like pumps, going into subsea, so how we manage that is going to be a huge reliability and integrity challenge.


Pig deal
The JIP's findings have helped strengthen the case for building in integrity management early in the design phase during the initial feasibility and front-end engineering studies for subsea systems. That lets operators plan for action well in advance of actually needing to do anything.

"With new fields today, a lot of them have the planned intervention capabilities, whereas with those built ten years ago, you had to go in and try to improve existing systems," says Strouse. "That was a lot more expensive."

Measures might include increased use of expensive corrosion-resistant alloys to help extend critical component life in very hot or otherwise hostile environments. Enabling simple ROV intervention and modular component swapping, using the latest sensors or building multiple access points into pipework for pigging all help lower the cost of IMR and support RBI.

"Pigging tech has changed radically," says Strouse. "Getting pigs into systems used to be a big deal, but today's launchers and receivers make it much simpler to put one into the field to inspect lines."

However, innovative techniques and equipment designs present their own reliability challenges. For example, chemical injection pumps have often failed more frequently than predicted.

"We're starting to see a lot more rotating equipment, like pumps, going into subsea, so how we manage that is going to be a huge reliability and integrity challenge over the next three to five years," says Strouse. "For example, we need to look at not over-pressuring the system and causing faults that way."

The industry is already responding to this need with equipment such as fibre Bragg grating (FBG) strain sensors that can detect early damage within twin-screw pumps. Continued innovation like this combined with increased integrity management adoption should ensure operators continue to spot subsea failures well before they occur.

ROV intervention is one way of cutting down costs.
Understanding failure mechanisms is key to anticipating problems.
Jason Strouse joined Wood Group Integrity Management in 2012. He attends and develops multiple risk assessment workshops, helps with RBI activities regarding the inspection, monitoring and testing of offshore assets, writes integrity management plans and works on industry best practices.

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