For several years, research has been conducted to find alternatives to thermodynamical hydrate inhibition. The recent deepwater developments have created new operational conditions where hydrate plugging could occur. Huge amounts of water are expected to be produced in deepwater oildominated operations. This new situation forced the industry to imagine new prevention alternatives. Self-inhibition based on natural surfactants has been investigated and fieldobserved. More recently, experiments have demonstrated the capabilities of appropriate flow conditions to restart operations in the hydrate domain. Based on field experiences and pilot loop tests, this paper will review conditions for which flow is expected to be successfully ensured within the hydrate domain and others corresponding to more hazardous situations.


The hazard of hydrate formation causing blockages in production lines remains today one of the main concerns to deepwater field developments. Consequently, hydrate control strategy may represent a major part of the design, resulting in high capital and operational expenditures.

Even if new methods have been discussed in the Literature1,2, the common process anticipated to remove hydrate plugs mainly consists in depressurizing the line in order to enable hydrate crystals to dissociate3. In addition to safety hazards regarding hydrate removal methods4, hydrate plug formation has a severe impact in terms of cost associated with removal operations and the resulting long-term shutdown of the production. Moreover, for oil dominated systems, depressurization might be ineffective due to the residual hydrostatic pressure resulting from the presence of liquid in the riser.

The present strategy of operators is therefore focused on the deployment of prevention methods that aim at producing outside the hydrate domain. This can mainly be achieved via pipeline insulation or chemical injection. Two cases can be distinguished: gas or gas-condensate fields, and crude oil fields. With respect to hydrate control, these two cases essentially differ in the quantity of water produced throughout the life of the field. Oil fields can rapidly produce a large amount of formation water to which injection water may add further in case of enhanced recovery. Gas fields typically produce condensed water in early field life. Formation water can then be produced at mid or late life but water quantity generally remains low compare to oil fields.

From an economical point of view, continuous injection of chemicals is thus acceptable for gas fields and corresponds to a better option than the installation of insulated lines. The proven technology, widely used by operators is the injection of thermodynamic inhibitors: methanol or glycol. However, many problems arise from such a technology in terms of large volume storage capacity, logistic of transportation, installation of large umbilicals, regeneration process for glycol, etc. The most promising option for the future is incontrovertibly the injection of the so-called LDHI's (Low Dosage Hydrate Inhibitors) including two different types of additives: the kinetic inhibitors5 and the anti-agglomerant additives6. It is true that their use in place of conventional inhibitors is still marginal. Nevertheless, one can expect, may be in association with complementary processes such as subsea water separation7, they will be more and more considered as an alternative option in the design of new deepwater gas fields.

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