Deep-water oil and gas developments are rife with technical complexity. That is certainly the case during well shutdowns – when hydrocarbon extraction is suspended during essential routine maintenance and vital components are exposed to the full impact of environmental conditions.
During shutdowns, the lower ambient temperature of deeper water can present a significant risk of hydrate formation within pipelines as the contents cool down. Cold temperatures and higher pressures can lead to pipelines becoming quickly clogged up with hydrates, ice-like compounds formed when water and hydrocarbon molecules mix under certain pressures and temperatures. Blocked pipelines can be out of action for long periods of time and unblocking them is expensive and difficult.
Oil and gas engineers have to perform complex calculations to work out to what extent the cool-down process will affect pipelines. Equipment and pipelines are then fitted with the required insulation to maintain sufficient temperatures during shut-down operations to reduce the likelihood of hydrate formation. But if the predictions are wrong, it can prove costly.
“A crucial stage of hydrate management for an oil or gas development is the thermal design, where engineers design features into the system for the avoidance of hydrate formation,” explains Liam Hewitt, oil and gas business manager at Frazer Nash Consultancy. “In oil pipelines hydrates form relatively slowly over the course of several hours, but in gas systems they can form quite rapidly during restarts – in seconds.
“In both scenarios if a hydrate plug forms in a pipeline, the logistics of trying to remove it can be quite challenging, and the pipeline can be out of service for several months or even a year. That timescale has significant cost implications and impact on production. So accurate predictions of when hydrates will form and designing mitigation such as insulation systems and the use of inhibitors are essential in increasing the viability of deep-water developments.”
Historically, finite element analysis (FEA) has been used to establish cool-down characteristics of subsea structures and equipment. But another corollary of deeper water developments is the requirement for larger and more complicated subsea systems, such as longer tie-backs and bigger manifolds.
In many cases, FEA techniques are not capable of performing the kinds of calculations required to adequately predict the heat loss and temperature distribution through more complicated components, where internal fluid flows are significant.
That’s why companies such as Frazer-Nash use more advanced software, principally Computational Fluid Dynamics (CFD), which offers significant benefits in terms of accuracy over traditional FEA in predicting oil or gas temperatures during cool-down events. CFD can also be used to identify regions of high heat loss through solid components, allowing improvements to the design and insulation schemes that are subsequently used.
Hewitt says this approach represents a radical shift in available design tools. “Up until recently, determining accurate cool-down times of critical or complex equipment required testing and tricky calibration of FEA models. With the advances of high-powered computers the price and duration of CFD modelling has come down significantly and is far more viable.
“CFD is much better at quantifying oil or gas temperatures and cool-down times than FEA as it models the actual fluid flow and convective heat transfer within the pipe. This gives you a better estimate of heat loss and cold spots and it allows better thermal management design for systems and equipment.”
Such an approach can make a huge difference for offshore operators, says Hewitt. “For instance, we recently did some work with an equipment supplier and operator who had gone through the usual design loop to try to maximise the cool-down time. They managed to achieve a cool-down time of about seven hours but operability of the development required a cool-down time of 16 hours to be met.
“So we worked with them using CFD to identify a few small design changes to the system, meaning that there was no need to add more insulation, and the cool-down time was increased to 19 hours. Knowledge of heat transfer mechanisms supported by CFD helped us to focus on where to put the effort and where the big gains could be achieved.”
Hewitt predicts that CFD will be used to produce more complex models of subsea systems, in particular predicting the actual hydrate formation over longer periods of time. He says CFD will increasingly be used to model the multi-phase nature of liquid and gas systems within offshore pipelines.
“We run the simulation until the first point at which temperature and pressure allows a hydrate to begin to form. In future, though, what we could do is start to predict the formation of a complete blockage across the entire section of the pipe – that’s a process that could take several hours from the point at which it first appears. Solidification modelling using CFD is performed in other industries and could be for the prediction of hydrate formation.
“There is also a joint industry project, for which we are gathering support, where we are looking to take a more risk-based approach to decision-making from flow assurance modelling, and hence hydrate prediction. That’s about adding some graduation between a black and white decision of ‘yes’ or ‘no’ it ‘will’ or ‘won’t’ form a hydrate at some point in its life. We understand that cost-benefit decision-making can improve flow assurance strategies and aid in the design of developments.”
Most of the work using CFD has been in deep waters in regions such as the Gulf of Mexico, the west coast of Africa, and Australia. But Hewitt says it might also prove useful for new developments in the North Sea, in sites to the west of Shetland. “Most of this type of work is being done in deep-water developments and tie-backs and most of the large new developments are happening there.
“Saying that, there are new developments in the North Sea and thermal design will be something which engineers will go through the loop of looking at. But pressures are lower and remediation in shallow water is much easier – 100-metre depth is far easier to work at than 2,000-metre depth.”