Reduce Hydrate Risk
(in Transient Phases)
Gas hydrates are one of the major flow assurance challenges for the industry and are expected wherever gas meets water at high pressure and low temperature. This is also a problem for oil producers (especially those using gas lift), who have a risk of hydrates forming at the well-head when wells are shut in and therefore cold. Operators address this by injecting chemical inhibitor ‘pills’ at the well-head during shut-in and for a period after start-up to avoid hydrates forming. The right amount of chemical inhibitor required to prevent hydrates forming during shut-in is not easy to calculate, and so operators may face a residual risk of blockages or conversely be injecting too much inhibitor and so unnecessarily contaminating hydrocarbons produced.
“It is a challenge that it takes 30 minutes to get the MEG back up at restart. There is currently a discussion about whether we should base our treatment volumes on a cost-benefit analysis or on our current extremely conservative approach”.—Major Operator, Australasia
“A more scientifically-based approach towards continuous improvement and validation. Cost savings associated with adopting a risk-based approach (resulting in very highly controlled risk). Ultimately the benefit of this technology translates into quality of hydrocarbon product (with regard to contamination in particular), which plays a big part in hydrocarbon accounting”.
—Independent Consultant, Global
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How We Solve It
We look at prevailing well conditions to assess the risk of hydrate formation and calculate the right volume of chemical inhibition required to mitigate this risk and the required duration for continued injection post-start.
This can lead to a reduction in chemical inhibitor use of between 20% and 50% or can simply provide assurance that the current dosage method and plan is sufficient and effective.