Severe slugging occurs in different parts of the total production system. Slug flow is a major, expensive headache for oil producers and it has a negative impact on the operation of onshore and offshore facilities. It causes reduction on separator efficiency and unnecessary shutdowns. The study presented in this paper covers the total process to analyze slug flow pattern in a network and possible ways of mitigation.The oil and gas distribution networks are complex and each present distinct but sometimes overlapping flow assurance challenges that will change over time. In this paper developed a workflow that simulate slug flow. The novelty of this workflow is the ability to perform a slugging analysis with different scenarios that mitigate slug flow. The fluctuations frequently lead to a reduction of separator efficiency caused by excessive liquid levels and pressure surges in the first stage separator. This solution, can provide a relative low-cost method to mitigate slugging and can help the operator to anticipate further decisions based on forecast production, although each system needs to be examined in detail to understand the current operation and the future performance changing the production conditions.

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As part of the sustainability and growth initiatives of all offshore operating companies to identify and prioritize optimum monoethylene glycol (MEG) injection rate in offshore operations, a hydrate management study was developed using dynamic simulation to optimize long-term planning of maintenance activities and to develop associated long-term maintenance budgets. This workflow includes a parametric study to understand and evaluate the impact of the insulation material as a mitigation measure where inhibitor injection is not possible. An economic analysis was performed to compare a base case (constant MEG injection rate) with a different scenario of an optimum MEG injection and the introduction of an additional production platform in 2018, where some of the main economic premises that need to be considered are included. The analysis evaluated a gas and condensate offshore system, based on three platforms that send their production to a process facility that treats a production rate at export conditions. After treatment, the gas is separated in two export gas pipelines. A dynamic simulation was used to obtain the MEG injection rate considering a physical model and a fluid characterization that included hydrate curves and phase envelopes. In addition to this study, pressure, temperature, holdup, and flow regime were calculated. It is not expected to have hydrate formation in the two export pipelines due to the insulation layer that allows an increase in fluid temperature. The insulation layer was obtained by performing a parametric study with the pipeline thickness. This is one of the suggested hydrate solutions from this study. The proposed workflow addresses the challenges of hydrate analysis by using an efficient and fast tool that can model different dynamic flow behaviors by running fast sensitivity runs for multiple transient scenarios (what-if-scenarios). This solution provides effective and low-cost MEG inhibition by eliminating unnecessary injected volumes at certain times.

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