Video: Hydrate Blockage Assessment in a Pilot-Scale Subsea Jumper
- Asheesh Kumar (Centre for Long Subsea Tiebacks, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia) | Mauricio Di Lorenzo (CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia) | Karen Kozielski (CSIRO Energy, 26 Dick Perry Avenue, Kensington WA 6151, Australia) | Philippe Glénat (TOTAL S.A.– CSTJF, Avenue Larribau, Pau Cedex 64018, France) | Eric F. May (Fluid Science and Resources Division, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia) | Zachary M. Aman (Centre for Long Subsea Tiebacks, Department of Chemical Engineering, The University of Western Australia, 35 Stirling Hwy, Crawley WA 6009, Australia)
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- Offshore Technology Conference
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- 2020. Copyright is retained by the author. This document is distributed by OTC with the permission of the author. Contact the author for permission to use material from this document.
- 4.5 Offshore Facilities and Subsea Systems, 4.2 Pipelines, Flowlines and Risers, 4.5 Offshore Facilities and Subsea Systems, 4.3.1 Hydrates, 4.6 Natural Gas, 2.1.3 Completion Equipment, 4.3.4 Scale
- Subsea jumper flowloop, Mono-ethylene glycol, Hydrate management, Thermodynamic hydrate inhibitors, Subsea tiebacks
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In subsea production operations, wellhead jumpers are one of the subsea facilities more liable to the formation of hydrate blockages during restart operations. To manage hydrate formation and optimize the amount of thermodynamic hydrate inhibitors (e.g. mono-ethylene glycol; MEG) injected, a newly-constructed jumper-like facility (the HyJump flowloop) has been developed in Perth, to simulate shut-down and restart operations over a range of superficial gas velocities.
The test section of the flowloop has a unique geometry to mimic subsea jumpers, with three low points and two high points standing 13′ 2″ tall. The test section is fitted with twelve pressure and temperature sensors spread regularly, a MEG sensor, a valve to simulate the wellhead choke, and a viewing window. In each test, the jumper low points were loaded with aqueous solutions of MEG (0 to 30 wt%) and pressurized with domestic Perth natural gas at a pressure of 1200 psig and pipeline temperature ranging from 41°F to 25.8°F (+5 to -4°C).
The extent of hydrate restrictions or blockages was evaluated through the dynamic pressure drop behavior observed throughout the flowloop. A closer assessment of the pressure drop trace during gas restart suggests that the severity of the hydrate restriction decreases as the MEG content is increased above 10 wt%. Further, our preliminary experimental results illustrate that severe hydrate deposition in the jumper could be completely avoided by injecting MEG at concentrations above 20 wt%. This corresponds to an approximately 50% reduction in MEG content, where ≈38 wt% MEG dosage was required for complete thermodynamic hydrate inhibition at the pressure and temperature conditions used in this trial.
Our unique flowloop facility offers new insight toward hydrate formation in complex subsea jumper-like geometries. Our findings may assist operators in controlling the extent of hydrate formation and deposition in jumper geometries, by optimizing the MEG injection and subsequently supporting lower-CAPEX tieback development concepts.