Predicting Hydrate-Plug Formation in a Subsea Tieback
- Simon R. Davies (Colorado School of Mines) | John A. Boxall (Colorado School of Mines) | Carolyn Koh (Colorado School of Mines) | E. Dendy Sloan (Colorado School of Mines) | Pål V. Hemmingsen (StatoilHydro) | Keijo J. Kinnari (StatoilHydro) | Zheng-Gang Xu (SPT Group)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- November 2009
- Document Type
- Journal Paper
- 573 - 578
- 2009. Society of Petroleum Engineers
- 4.2.4 Risers, 4.3.1 Hydrates, 4.1.4 Gas Processing, 4.1.5 Processing Equipment, 4.2 Pipelines, Flowlines and Risers, 1.10 Drilling Equipment, 5.2.1 Phase Behavior and PVT Measurements, 5.9.1 Gas Hydrates, 4.3 Flow Assurance, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 4.3.4 Scale, 7.2.1 Risk, Uncertainty and Risk Assessment, 4.3.3 Aspaltenes, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow, 1.3.2 Subsea Wellheads
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Field data from StatoilHydro on hydrate-plug formation in the Tommeliten gas/condensate field are compared to predictions of the hydrate-growth model (CSMHyK-OLGA) for four typical operating scenarios: steady-state operation with failure of inhibitor injection, restart of an uninhibited line, restart of an underinhibited line, and restart of a depressurized line.
Although the CSMHyK model was designed for oil flowlines, the model is able to predict the correct time scale for hydrate-plug formation in this gas/condensate tieback. The predicted locations of the plugs are often farther upstream than observed in the field trials. This is mainly because of the assumption of a "hydrate/oil slip factor" of zero, which forces the hydrate to accumulate where it initially formed. In reality, hydrate agglomerates would be carried further downstream before eventually jamming in dips.
Predicting where and when hydrate plugs will form in subsea tiebacks is of increasing importance as the industry strives to manage the risk of plugging in oil and gas flowlines while minimizing the use of costly and environmentally harmful chemicals for hydrate inhibition. The Colorado School of Mines has been developing the CSMHyK model for the past 5 years, in collaboration with the SPT Group and several leading energy companies.
Hydrates continue to be the most prevalent flow-assurance problem in offshore oil and gas operations: an order of magnitude worse than waxes and two orders of magnitude worse than asphaltenes (Sloan and Koh 2008). The risk of hydrate plugging increases as the industry moves into deeper water with corresponding higher pressures from the additional liquid head and to longer tiebacks in which the production fluids cool deep into the hydrate-stability zone. A recent review of hydrate-plug-prevention strategies is provided by Mokhatab et al. (2007).
The cost of thermodynamically inhibiting such tiebacks under steady-state and transient operations can be prohibitive. It is often not possible for the flow-assurance engineer to avoid the hydrate-stability zone in all foreseeable operating scenarios. Instead, a risk-management approach is often adopted to prevent hydrate-plug formation (Kinnari et al. 2006; Pausche et al. 2002). Because of the potentially severe economic impact of forming a hydrate plug, it is critical to develop models that the flow-assurance engineer can confidently apply when making a risk assessment of a new field design or restart procedure.
A number of models have been proposed previously for hydrate-formation rates in laboratory-scale systems. The models are based either on chemical-kinetics equations (Vysniauskas and Bishnoi 1983; Englezos et al. 1987; Christiansen and Sloan 1995; Lee et al. 2005) or interfacial-mass-transfer resistances to hydrate formation (Skovborg and Rasmussen 1994). The applicability of these models is generally limited to apparatuses of a geometry similar to that of the apparatus in which the measurements were taken. The Colorado School of Mines has been developing a model for hydrate formation in industrial-scale flowlines in conjunction with SPT Group since 2003. The model, CSMHyK, is incorporated as a plug-in module in the transient multiphase-flow simulator, OLGA.
CSMHyK was developed initially for oil flowlines, but has also proved a valuable tool for Chevron when making design decisions for new field developments. Key to the development of CSMHyK has been the extensive testing against industrial-flowloop data from ExxonMobil and the University of Tulsa (Boxall et al. 2008) and against industrial field data as described in this paper.
No published prior method exists that enables predictions similar to this work. Recently, Calsep has been developing an alternative model for hydrate formation in industrial systems. The model, Flowasta, is based on mass-transfer rates between the hydrocarbon liquid and the water phase. The model currently relies on fitted paramerers for the mass-transfer resistances, and work is in progress to validate the model against industrial-scale flowloops.
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