Cold Flow?
The concept of cold flow is a combined hydrates/wax philosophy based around allowing hydrate (and wax) to form but in such a manner that the flowline is not blocked - unlike the famous picture from Petrobras Barracuda above!
The driver for cold flow has been the development of deep water oil fields where low temperatures and possibility of shut-in rule out the use of low dosage inhibitors and the amount of water present makes the dosing of conventional inhibitors unacceptable on cost, logistical and environmental grounds.
I 'm currently working on a deep water project and cold flow was just randomly mentioned (and I do mean randomly!). Whilst I understand the principles, I must admit I wasn't up to date on what had been done elsewhere to date and I still need to do a lot more reading of papers to find out.
However I rediscovered a previous review we'd performed about 10 years ago and was really taken by the approach used by Shell for their Mensa development. It makes for a very interesting philosophy, although I'm not sure I would be brave enough to recommend it for one of my own projects!
The hydrate inhibition philosophy used for the Shell Mensa Development was based around the use of conventional inhibitor injection but had certain cold flow design features. The flowlines from the 3 individual subsea wellheads were un-insulated and were installed in such a way as to ensure that no self-burial of the flowline into the seabed would occur. These features were intended to help prevent flowline blockage in the event of a failure of inhibitor dosing to one of the wellheads. Hydrate would rapidly form in the affected flowline. Ideally this hydrate would be in the form of small hydrate particles (having grown quickly) and would flow into the manifold where mixing with the inhibitor dosed fluids from the other wells lead to hydrate dissociation. If the hydrate were to agglomerate the intention was that the blockage would occur in the flowline rather than in the export line, allowing continued production from the remainder of the field until remedial action could be taken.
Britannia (1998 start up) tackled the potential problem by designing a jacketed flow line bundle from remote subsea wellheads to the platform circulating heating medium out and back to maintain flow line temperature above the hydrate region even when the production flow was shut in. WHRU provided heat for the heating medium.
Cold flow comes back in the game in the current challenging environment. We got a much better understanding of physico chemistry and slurry rheology. However, as far as I am concerned main issue is interaction between wax & hydrates which is quite complex to characterize to derisk a cold flow concept, as well as operational efficiency linked to pigging requirements. Fascinating!
The cold flow concept has been a long time research topic at Shell but as a full concept it never made it out of the lab as far as I know. You essentially need to install a piggable cooling loop internally treated with low surface energy coating and find a way to reliably and frequently run subsea bypass pigs. And find a project willing to adopt multiple new technologies and be the Guinea pig when there is already a proven and available way to produce via conventional FA strategies. The ultimate goal was to enable production from very long offset fields beyond reach using insulate/blowdown strategy, but you then need to also qualify additional technologies such as subsea pumping, long distance subsea power delivery and/or remote power generation. And all this was being proposed 10-20 years ago.
Hi Chris, thanks for sharing. Likewise, interested in cold flow principles and technologies. It's never the first choice strategy but always worth considering when conventional strategies are too costly, including late life when cost/benefit encourages a higher risk strategy and there is field experience of excursions into the hydrate region (plus lab testing). In your example, was the flowline designed with cold flow in mind and was insulation considered too expensive / disproportionate to the risk being managed (i.e. if inhibitor is unavailable to a single well)? Or was the cold flow argument being used to close out a Hazop action or similar scrutiny of the inhibitor availability? Either way, credit for using cold flow analyis to simplify or justify the design.