Bringing the First BP-Operated Subsea-to-Shore Gas Field Into Production: Flow-Assurance Lessons Learned
- Amrin Harun (BP Egypt) | Norris Watt (BP Egypt)
- Document ID
- Society of Petroleum Engineers
- SPE Projects, Facilities & Construction
- Publication Date
- June 2010
- Document Type
- Journal Paper
- 65 - 75
- 2010. Society of Petroleum Engineers
- 5.4.6 Thermal Methods, 5.2.2 Fluid Modeling, Equations of State, 5.2.1 Phase Behavior and PVT Measurements, 4.3.1 Hydrates, 3.4.1 Inhibition and Remediation of Hydrates, Scale, Paraffin / Wax and Asphaltene, 2.7.1 Completion Fluids, 2.2.2 Perforating, 4.3 Flow Assurance, 5.4.2 Gas Injection Methods, 4.6 Natural Gas, 2.4.3 Sand/Solids Control, 4.1.5 Processing Equipment, 4.5.10 Remotely Operated Vehicles, 5.3.2 Multiphase Flow, 4.2.4 Risers, 4.1.4 Gas Processing, 7.2.5 Emergency Preparedness and Training, 4.1.2 Separation and Treating, 4.2 Pipelines, Flowlines and Risers, 5.2 Reservoir Fluid Dynamics, 2.4.5 Gravel pack design & evaluation
- gas hydrates, Taurt field
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Taurt field, located in the Mediterranean Sea in 108-m water depth, is the first BP-operated subsea-to-shore gas development. Phase 1 of the project consists of two subsea wells producing directly from the subsea manifold to the onshore gas-processing plant with a 68-km, 20-in. pipeline. The field has been brought into production and was successfully ramped up to 230 MMscf/D despite facility constraints during initial startup. The main flow-assurance issues experienced during the initial startup are hydrate risks because of Joule-Thomson (J-T) cooling and liquid-production handling onshore, particularly because of potential completion-brine return.
The experience during initial startup highlights the importance of collecting good fluid samples during exploration and appraisal, and obtaining downhole and wellhead pressures and temperatures during flowback. Confirming the condensate yield helps prediction of liquid holdup in the pipeline that will affect the prediction of liquid production coming onshore during ramp up. More-accurate prediction of the wellhead temperature affects the requirement for hydrate inhibitor, which also affects the liquid holdup in the pipeline and liquid production coming onshore.
Transient simulations help in selecting the dewatering strategy to be either a pigged or a pigless operation by predicting the amount of remaining water and how it impacts the production ramp up. Simulations also help prediction of the liquid production for setting up temporary liquid-handling facilities to prevent the possibility of completion-brine return upsetting the processing plant.
Comparison with the actual liquid-production data suggests that simulations should have been performed with less-conservative condensate yield, although predicting the completion-brine return onshore is still difficult. After obtaining the latest fluid composition and the actual operating conditions, the hydrate-management strategy was revisited, and this resulted in cost savings and simpler operating procedures.
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