Operators of aging subsea assets have a unique opportunity during the next decade to extend the operating lives of what will prove to be some of the most robust equipment ever built to extract offshore hydrocarbons. In the late 1990s, when this generation of equipment was installed, uncertainty about its performance in a deepsea environment produced 20-year designs that were based on conservative assumptions about how conditions would affect corrosion, motion and fatigue. Generally, this is good news for life extension.
The benefit of subsea field experience has since refined those views; for example, less conservative assumptions have led to new equipment designs being more narrowly defined and cost-effective. It also has offered more visibility of the potential for fatigue and corrosion in equipment that operators have historically struggled to inspect, such as manifolds, subsea pipelines, steel catenary risers, umbilicals and flexibles.
While it remains impractical to pull those components to the surface for a thorough inspection—and often too costly or risky to pig subsea pipelines—advances in technology, data science and operating experience now offer better insight into the condition of “uninspectable” equipment.
Inspection life cycle
During the life of a field, assets undergo an inspection review cycle: design, fabrication, installation and preliminary inspection. Later in the field’s life, it is important to establish an initial starting point, which entails a reassessment of the design and whether it was installed as planned.
Comparing the post-installation inspection to the asset’s current condition can reveal if it and its environment have behaved as expected.
For example, a good place to start a riser inspection is with the top hangoff region of the platform for unusual wear and tear. Cleaning the marine life of the flex joint, for example, will reveal its condition.
It is critical to look through the water column, especially for external damage. Are the strakes, orbs or bearings still there? Because strakes limit vortexinduced motion (and therefore the stresses that cause fatigue) caused by ocean currents, they are a key way to assess an asset’s remaining life.
A similar close inspection of pipelines will reveal the rate of anode consumption, which are critical points for corrosion. The state of the anodes offers insights about whether overall cathodic performance is meeting design expectations. While internal pipe inspections are not always possible, external assessments can reveal a lot, beyond obvious external damage. The position of the pipe as compared to where it was originally installed can reveal operational behaviors. Most sections of pipe lie on the seabed, where movement leaves traces, which may have exceeded original expectations. Excessive movement raises the potential for fatigue.
Pipes move, so it is important to determine whether any obstructions have prevented movement. If, for example, the pipe is where it was originally installed, then something may be limiting its motion.
It also is critically important to monitor the location of pipe spans against their original placement. High currents shift the seabed, prompting pipes to settle on a terrain’s high spots or bring the lower sections to the seabed ground. This can compromise support for the span, or lengthen it, with the obvious implications for fatigue life.
The offshore industry has entered the era of “smart” operations, but most data generated from normal onsite operations are not gathered specifically to measure the life of the equipment. However, data derived from production, metocean and external events still hold insights into the life cycle of the asset.
Production data, for example, reveal whether the volume, pressure and temperature—as well as crude characteristics such as sweet versus sour, water content, H2S and CO2—met the expectations of the original design. If the original assumptions on water, corrosive fluids or chemical inhibitors differ from expectations, then the potential for a corrosion problem escalates.
Production data also record how many startups and shutdowns a well has undergone. For the manifolds and pipes on the seabed, post-production assumptions are that a relatively constant temperature will be maintained. Stop and start cycles raise and lower temperatures, even with insulated pipe, causing materials to expand and contract.
Unlike on drawings, where pipelines often are represented as straight lines, on the seabed they often are curved in three dimensions. When wells go into production, they heat up and the curves push out; when they are shut off, temperature falls and they pull back.
Evidence of this can be seen on the seabed, and the movement and frequency of these cycles may have impacted fatigue. Production data should be compared to the original design assumptions.
Records of environmental conditions offer insights into the risk of fatigue. If the asset is located next to metocean buoys or other recording devices, good data are available. But if not, then environmental performance is recorded on most platforms and should be reviewed.
Assessments of a system’s life have been greatly enhanced by the emergence of new analytical tools. Typically, operators have used “response amplitude models” to estimate the reactive behavior of a waterborne asset in the original design. With historical operating data available, it is possible to build a time-domain model using performance data. The result may or may not support life-extension goals, but it will provide a better picture of the asset’s consumed/ remaining life. The same can be extracted from metocean with regard to vessel direction, and therefore actual versus estimated stress forces.
If necessary, fatigue testing of similar equipment can offer useful performance analyses. The original design projections for fatigue should have been based on the best available curves; current curves may indicate a change. The curves themselves may not have changed, but industry performance may suggest a more appropriate curve for the specific location or asset design.
For the present class of offshore assets under life-cycle review, the original designs were probably based on working-stress analyses. For life-extension purposes, better insights would be derived from load-factor resistance analyses, which focus more on equipment performance (i.e., how much it can take) to determine how much it may have left.
The new analysis should include any full-scale testing results that may have been done. The operator should review the reports from the factory acceptance testing and site integration testing that were done before installing the equipment. Lastly, the asset’s photographic history often is overlooked when assessing its present condition; pictures and videos taken during or post-installation may offer insights into how it was behaving.
With the benefit of 20 years of operational data at hand, a recalculation of the expectations for the design will help to determine what was likely to have been consumed and to more accurately forecast future conditions. This reevaluation may or may not support life-extension goals, but it will likely give owners a better understanding of the present condition of the equipment that is notoriously hard to inspect.
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