Predicting Hydrate Blockages in Oil, Gas and Water-Dominated Systems
- Luis Eduardo Zerpa (Colorado School Of Mines) | Zachary Mark Aman (Colorado School of Mines) | Sanjeev Joshi (Colorado School of Mines) | Ishan Rao (Colorado School of Mines) | E. Dendy Sloan (Colorado School of Mines) | Carolyn Koh (Colorado School of Mines) | Amadeu Sum (Colorado School of Mines)
- Document ID
- Offshore Technology Conference
- Offshore Technology Conference, 30 April-3 May, Houston, Texas, USA
- Publication Date
- Document Type
- Conference Paper
- 2012. Offshore Technology Conference
- 5.3.2 Multiphase Flow, 4.3.1 Hydrates, 5.2.1 Phase Behavior and PVT Measurements, 4.6 Natural Gas, 4.3.4 Scale, 4.2.4 Risers, 4.2 Pipelines, Flowlines and Risers, 4.3 Flow Assurance, 4.2.5 Offshore Pipelines, 5.9.1 Gas Hydrates, 4.3.3 Aspaltenes, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene
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The formation of natural gas hydrates in deep subsea pipelines is one of themost challenging flow assurance problems. The development of a comprehensivehydrate model (CSMHyK), which predicts temporal and spatial hydrate formationand plugging in flowlines of oil-, water- and gas-dominated systems, will havesignificant utility in flow assurance. This empowers the engineer to design andassess oil/gas transport facilities, with a focus on prevention, management orremediation of gas hydrate formation and blockages. In the current work, wepresent improvements to the hydrate aggregation module used for oil-dominatedsystems, based on experimental data, which account for temperature,particle-particle contact time, excess water, and the presence of surfaceactive compounds. Second, we have extended CSMHyK to water- and gas-dominatedsystems, and have developed fundamental models based on flowloop and laboratorydata. In water-dominated systems, we present a new mass transfer-based growthmodel and hydrate plugging criterion, based on fluid velocity. In gas-dominatedsystems, we present a combined heat and mass transfer model for hydrate filmgrowth on pipe walls. These models are applied to a typical well/flowline/risergeometry used in offshore facilities. This model improves our capability topredict hydrate formation and blockages, by considering dynamic aggregationphenomena in oil-dominated systems, flow regime transition in high water cutsystems, and hydrate film growth in gas saturated systems.
Natural gas hydrates form when small guest molecules contact liquid water athigh pressure and low temperature (Sloan and Koh, 2008), which are typicaloperation conditions of subsea pipelines. The formation of natural gas hydratesin deep subsea pipelines is one of the most challenging flow assurance problems(Sloan, 2005), involving significant design efforts to prevent the formation ofundesirable hydrate plugs.
It had been recognized that predicting hydrate formation conditions usingthermodynamic calculations (with excellent accuracy) is not sufficient toestimate hydrate plugging risk (Sloan, 2005). Instead, this can be used todesign hydrate avoidance methods (e.g., chemical injection, thermal insulation,active heating, and pressure reduction), keeping the systems out of the hydratestability region (Creek et al., 2011). The offshore oil/gas industry hasprogressed toward using longer tiebacks (Ronalds, 2005) to connect subsea wellswith platforms, rendering hydrate avoidance methods economically unfeasible.The alternative would be to consider hydrate management approaches, wherehydrates are allowed to form, but the plugging risk is low (Creek et al., 2011;Sloan, 2005). Models for hydrate formation kinetics coupled withtransportability models may be helpful during the design and assessment ofhydrate management approaches, providing estimates of the amount of hydratesthat could form and its transportability in specific scenarios, to estimatehydrate plugging risk.
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