Gas hydrates pose the major flow assurance problem in the production and transportation of oil and gas. As production moves to hasher environment (deeper water, longer tiebacks, more produced water), preventing, managing, and remediation of gas hydrates are central for safe and continuous operation. In this paper, we will provide an overview of the approaches used in the prevention, management, and remediation of gas hydrates in oil/gas flowlines. The approaches developed are based on the research performed at the Center for Hydrate Research at the Colorado School of Mines over several decades. The paper will discuss how hydrate formation conditions is estimated for prevention, how hydrates formation occurs in flowlines for management, and how hydrate dissociation occurs for remediation. The understanding of hydrate formation in multiphase flow is an evolving area, even though significant knowledge has been gained over the years in terms of fundamental processes for hydrate nucleation, growth, agglomeration, deposition, and plugging. Each of these areas is part of a comprehensive model describing the various stages of hydrate formation. We will overview the process for hydrate formation in oil-dominated, water-dominated, and gas-dominated systems, and the tools developed that can be applied to addressing hydrates in the flow assurance of oil/gas flowlines.
Gas hydrates play a significant role in the flow assurance of oil and gas flowlines, posing one of the most serious problems relative to the formation and deposition of other solids (e.g., wax, asphaltenes, scale, etc.). The formation of gas hydrates in flowlines can be not only fast, but also in large volumes, causing unexpected operational problems.1
Industry has traditionally taken the approach of preventing gas hydrates from forming in flowlines by injection of so-called thermodynamic inhibitor, THI (e.g., methanol, monoethylene glycol, ethanol), which inhibits hydrate formation in the free water phase. As seen in Figure 1, in this approach the THI shifts the hydrate equilibrium curve to more severe temperature and pressure conditions, thus allowing the flowline to operate outside the hydrate stability region. While effective in preventing hydrate formation, the costs and quantity of chemical required can be significant.2
Over the last two decades, industry has looked for an alternative approach to the complete prevention of gas hydrates in flowlines by shifting to a management strategy of hydrates, that is, to allow hydrates to form in flowlines but prevent their agglomeration to form a blockage.3 Such a strategy would allow industry to tolerate hydrates in the flowlines and reduce the cost and quantity of chemicals used in their operations. Using this approach, it is therefore important to have a good understanding how hydrates are forming, agglomerating, depositing, and jamming a flowline, so that one can assess the risk of hydrates in the flowlines and the potential for a blockage to form. This approach has been implemented to some extent in the last decade in industry with the use of anti-agglomerants (AAs) and low-dosage hydrate inhibitors (LDHIs).
There cases where the formation and blockage of flowlines with hydrates is inevitable, due to unplanned shutdown or abnormal operating conditions originating from equipment malfunction. In these cases, industry must be able to remove the hydrate blockage(s) in the flowlines before normal operation can be resumed. The removal of hydrate blockages can be a tenuous process as the dislodging of the hydrate blockage can generate a projectile in the flowline.