Preventing hydrates from forming is critical for offshore oil and gas operations, so that fluids can flow smoothly from reservoirs to surface treatment units. Methane and water crystals that form at high pressure and low temperatures, hydrates can plug lines, especially during production shutdowns. The need to prevent them forces the industry to use complex, and thus more expensive, architectures. That was the spur for our new approach to prevent hydrate formation while sharply cutting costs.
An avoidable - but expensive to prevent - risk
Under certain pressure and temperature conditions, water and light hydrocarbons interact to form gas hydrates. The formation of hydrate crystals needs to be avoided, because it can plug lines. The risk rises during production shutdowns, when the fluids cool down.
Preventing hydrate plugging is a big part of flow assurance, since delayed detection can cause costly operating problems. Various solutions are used during production to prevent hydrate formation and keep fluids flowing:
- Thermally insulating, even heating, subsea lines, to prevent fluid temperatures from dropping into the hydrate formation region. Though widely used in the industry, this expensive solution is reaching its practical limits, as the distance between wells and surface facilities increases.
- The use of thermodynamic additives to inhibit the hydrate formation. Massive amounts of “antifreeze” such as methanol or glycol are injected, mainly at well locations. This can significantly affect the development and operational costs of the project, since the antifreeze may have to be separated, recovered and regenerated in the surface facilities. Lastly, the antifreeze’s HSE impacts also have to be considered.
- The use of low-dosage advanced chemical additives at well locations. These additives can either prevent hydrate formation (kinetic inhibitors) or move hydrates through the lines in the form of finely dispersed particles (dispersants or antiagglomerates). We’ve used this recent and promising solution for a few developments. However, it is only suitable for fields that don’t produce much water, such as gas and gas condensate fields. The environmental impacts of such chemicals also have not to be discarded.
So preventing hydrate plugging, first, affects the design of offshore architectures, and then requires complex operating procedures, especially for restarting production. This has a significant impact on CAPEX, OPEX and production shortfalls.
An Innovative Approach
We’ve been studying the kinetics of hydrate formation, both through joint industry programs (JIPs) and in our own research labs, for decades. We’ve determined that certain crudes have an inherent ability to delay and even block hydrate formation. Leveraging our solid expertise, we’ve developed a method called Hydrates Induction Time of Crudes, or HITC.
We replicate hydrate formation in the lab by varying different parameters such as type of hydrocarbon fluid, percentage of water and gas, and operating conditions (pressure and temperature). Our lab experiments help us predict hydrate formation kinetics and more precisely highlight the pressure and temperature conditions at which massive hydrate formation occurs.
Such lab data is essential for precise risk mapping. Integrated into a digital application to assess and monitor hydrate formation risk, such mapping lets us optimize our operating procedures and extend our subsea lines’ operating window. In other words, we can operate our production lines in the hydrates’ thermodynamic region, while staying away from the operating conditions of rapid and massive hydrate formation.
This offers a number of advantages:
- Less complex design of our production line architecture (thermal insulation, redundant lines), significantly cutting the cost of facilities.
- Simplifying onsite operations during planned and unplanned shutdowns, sharply reducing OPEX and shortfalls.
- Unlocking satellite reserves that weren’t economical to develop before on a standalone basis.
First-time application in Angola
The new HITC approach offers new opportunities for our mature fields, notably Dalia Phase 3, located in Block 17 in Angola. We observed that with this field’s oil, hydrates take 72 hours to form, when crude is subcooled up to 6.5°C in the hydrates thermodynamic region (reference curve is the Hydrates Dissociation Temperature). Combined with down sloping bathymetry of the production, these chemical properties enabled us to use a single, simply insulated (wet insulation) production line to tie back new wells more than 3 kilometers away from our existing facilities. The dedicated budget was only half that required for a conventional approach.
This simplified development plan is a genuine innovation for Total. For the first time on an offshore field, there are no operational measures planned to prevent hydrate formation in the production line during shutdowns.
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