Multiphase transportation is more and more contemplated in the development of oil and gas fields both in conventional and frontier areas (from remote satellite fields to deep offshore). This new environment has set forward new challenges in the field of hydrate plugging prevention in subsea flowlines. Increases of transportation distances and water depths place the fluids well inside the hydrate formation domain, and hence threaten flow in multiphase export lines. In such conditions, conventional hydrate prevention (alcohols, insulation, heating) can become very expensive and can in some cases jeopardize the economy of the project. To challenge this anticipated situation, the oil and gas industry has been looking for low dosage inhibitors: kinetic inhibitors which can delay hydrate crystallization, anti-agglomerants which let the hydrate crystallize but ensure their transportability in a slurry. This second process creates a water-in-oil emulsion which remains a transportable suspension after crossing the hydrate equilibrium curve. We have investigated whether this process could occur by itself with some surfactants naturally present within some crudes. Some research works have confirmed that some "natural surfactants" such as resins and asphaltenes have properties similar to synthetic surfactants. Since 95, extensive experimental work has been done at the University of Bergen (1, 2) and Elf research center (3) on a 1" loop with different crudes and fluid blends. The hydrodynamic tests have demonstrated the capability of natural surfactants to prevent hydrate plugging. Based on these results, an experimental methodology to evaluate hydrate transportability of a given crude has been developed. This method could reduce the need of inhibitors during the first years of production and thus result in large savings. With the present development of subsea-water separation technology, this process could further become a standalone alternative. P. 509

Control of paraffin deposition is addressed in early phase of new field developments, as part of the fluid-related effects on the flow performance of the multiphase transportation system. Paraffins are precipitated by a decrease of the fluid temperature. During the design phase, a combination of experiments and modeling is used to predict potential wax related problems and determine possible solutions for wax control. High reliability is required from wax deposition models in order to avoid over protective operational guidelines, over design of the transportation system and thereby reduce cost in terms of insulation, pigging and chemical injection. The main objective of this study is to compare wax deposition predicted by a simulation model to operational data for two different North Sea fields. The first case contemplates a 10-inch, approximately 21 km long multiphase and subsea production pipeline from the High Pressure gas condensate field A to the central gas-processing complex. The production has now come to an end. The second case is a single phase, stabilized oil being transported through a 16 inch, approximately 43 km production pipeline from a processing platform at field B to field C for storage and offloading. OLGA 2000 with wax module has been used for the dynamic wax deposition simulations. The physical and thermodynamic fluid properties used in the simulations are also presented and discussed. Various model parameters and their influence on modeling results are evaluated. Field experience after many years of production is available from the gas condensate field A. Although wax deposition was predicted in the gas condensate line, no significant deposit has ever been observed. Wax control for the field B pipeline is currently based on regular pigging every few days combined with continuous injection of wax inhibitor. There has not been sufficient field data available for a very detailed comparison with modeling results. Anyway, operational experience from two very different fields gives some important insight into the strengths and weaknesses of current modeling tools and practice. A main conclusion of this paper is that wax deposition under field conditions seems to be less severe than predicted by the model for the multiphase gas condensate line, while it seems to be reasonable agreement between modeling and field experience for the single-phase oil case. Introduction Wax deposition occurs on the inside surface of a flowline when the pipe wall temperature falls below the Wax Appearance Temperature (WAT), or cloud point of a paraffinic hydrocarbon liquid flowing in the line, and is lower than the bulk fluid temperature. The current approach in prediction of wax control strategy for new fields developments, is based on two steps. First, necessary experiments and simulations are performed in order to establish the wax deposition potential for a given fluid composition and thermo-hydraulic conditions. The degree of deposition will depend on the amount of wax components dissolved in the oil available for deposition, the rate of heat loss to the surroundings (or the temperature gradient at the pipe wall), the shear rate at the wall, the viscosity, water cut etc., and can be estimated using commercial software packages. The prediction models are still not very accurate, but they are believed to provide reasonable estimates of the rate of wax deposition and thus provide a basis for assessing the needs for wax control. The wax control strategy is then defined by taking into account other flow performance constraints and wax specific requirements. There are several methods for wax control in pipelines, such as pigging, chemical injection, thermal insulation and active heating. Currently, insulation and pigging are the most widely used methods. In an early phase and design phase evaluation, a maximum wax layer thickness of 2–3 mm is often used as a criterion for when a pipeline should be pigged.

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High water flowrates envisaged in deepwater oil production systems create severe technical hurdles. In steady-state flow design conditions, adequate insulation of moderate length subsea flowlines and risers is expected to maintain the fluids out of the hydrate domain. The restart operation after shutdown will on the other hand need specific operational guidelines and design solutions to avoid hydrate plugging. Operational procedures may involve hot crude displacement or injection of thermodynamical inhibitors. Plug formation has by far a more serious consequence on the production regularity at the deepwater environment than at shallow water. A new R&D project was launched to identify cost effective and easily implementable procedures and build more confidence on transient operations with particular focus on start-up. Restart operations were experimentally simulated on a properly instrumented multiphase pilot loop in order to observe and analyse the flow conditions within and outside the thermodynamic hydrate domain. Different fluid systems were tested at different hydrodynamic conditions. The results suggest that a high energy hydrodynamic start-up procedure would allow to restart the production within the hydrate domain while low energy start-up would promote formation of hydrate plugs. In the low energy start-up the presence of the oil phase was observed to reduce the risk for hydrate plug formation. 1. Introduction The hazard of hydrate formation causing blockages in production lines is an essential challenge to deep-water developments. The current practice in selecting hydrate control strategies is commonly based on the use of hydrate equilibrium data only, without taking into account the other system characteristics as fluid properties, distribution of phases and the physical design of the production system. This can in many cases be quite a conservative approach giving a significant negative impact on the project economy. This overcautiousness is based on a lack of understanding of the hydrate formation and plugging tendencies of the transported fluids in any type of flowing condtions. Clearly, substantial savings in capital and operational expenditures could be achieved by optimizing the hydrate control strategy. The state-of-the art in the hydrate control area has not yet come so far as to establish criteria and an experimental methodology that would enable one to determine conclusively whether safe operation inside the hydrate region (in the pressure-temperature plot) is possible or not. It is well known that certain production systems have been successfully operated within the thermodynamic hydrate domain. One of the reason for such behaviour could be the role of indigeneous natural surfactants present in the oil. In a previous JIP called "Hydrate blockage prevention through crude oil natural surfactants" it was demonstrated that some components/class of components naturally present in some crudes indeed play a key role in preventing hydrate plugging. Some field cases have reported that multiphase transportation in the hydrate domain with up to 30% water cut has been possible without addition of any chemical. These so-called "self-inhibition through natural surfactants" did not prevent hydrate formation, but under certain conditions they avoided the blockage of the flow line by making the hydrates transportable in the form of slurry.

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