Since Christmas I have been busy continuing with the detailed design phase of a new subsea tieback. In place of the usual entry that I write detailing the extents of my day job, today I thought I would provide an insight into the economic and technical drivers behind using a subsea tieback. This entry I suppose is aimed at students who have yet to have much experience in the economic criteria used to evaluate projects.
To take a quick step-back: a quick explanation of a subsea tieback. In the early days of offshore exploration and production of hydrocarbon fluids a platform would typically be constructed to produce from one field (if large), or 2-3 at most if they were in close vacinity. Today, multiphase resevoir fluids can be transported through pipelines over 100's of kms before reaching a reception facility. In the case of the subsea tieback I am working on the receipt of fluids occurs at an existing fixed jacket platform.
Fluids exist in the resevoir in multiple phases: i.e. immiscible liquids, miscible liquids, vapour, water, solids etc. meaning that transporting them in the their raw state requires no immediate separation. By flowing them back to an exisiting platform the costs of the project can be significantly reduced as no offshore production facility needs to be constructed. Alternatively, the subsea line could be directed to an existing/new onshore facility which makes construction/logistical costs a lot less.
Issues with flowing the fluids in multiphase fashion primarily occurs outside of normal operation, i.e. transient operations such as start-up, shutdown, pigging etc., but can also occur in normal operation. Two of the main issues are hydrate formation and intermittent liquids production, known as slugging.
Hydrates form at low temperatures and high pressures and can block lines presenting very expensive/hazardous problems. These conditions can exist in a subsea pipelines prior to start-up or after a prolonged shutdown. In this instance the reservoir can pressure up the line and fluid can cool down to the ambient temperature, i.e. conditions can fall inside of the hydrate formation envelope. To mitigate this the fluids can be inhibited with methanol, or other hydrate inhibitors, to bring the hydrate envelope inside the line conditions until the pressure reduces and temperature increases upon opening of the production choke valve.
Hopefully this small example provides a typical engineering trade-off for new subsea lines, i.e. cost savings versus scale/complexity of design. Next time I hope to give some insight into the extra-curricular life of a process engineering graduate.
