LNG Book

Subsea tie-back development

Subsea tie-back development

  • the overall capital expenditure can be decreased by utilizing the processing capacity on existing platform infrastructures, rather than by continuing to build new structures for every field.
  • The economics of having a long tie-back are governed by a number of factors specific to that field

: Distance from existing installation;

: Water depth;

: Recoverable volumes, reservoir size, and complexity;

: Tariffs for processing the produced fluids on an existing installation;

: The potential recovery rates from subsea tie-backs, usually low due to limitations in the receiving facility’s processing systems;

: The potential recovery rates in case of building new platform wells, usually high due to easier access to well intervention and workovers.

Host of subsea tie-backs

Additional components

  • Dual flowlines with an end-to-end loop, which are customarily used for subsea tie-backs, provide a full circuit for the pig so that the pig can pass through the flowline:
  • Subsea boosting and processing are aimed at increasing the flow of crude from the reservoir to the process plant or at reducing the need for topside processing equipment.
  • Multiphase boosting pumps can either be installed topside or at the subsea wellhead.
  • Another method used to pump the fluids to the processing location is to use gas-lift risers. It involves injection of a predetermined rate of gas into a production flowline (or riser) on the seabed (oil-producing systems only).
  • This injected gas is provided by the host facility, through a gas-lift riser. Gas-lift risers can also be utilized for production enhancement, flow stabilization, and flowline depressurization and to control severe slugging.

Tie-back selection and challenges

  • Factors to consider

: Cost – Lowest life-cycle cost (i.e. lower CAPEX and OPEX);

: Safety – Safety of personnel and other stakeholders in construction and operation;

: Environment: Impact of development on the environment;

: Technology innovation or transfer: Trial of new technology or transfer of existing technology and know-how;

: Capacity utilization: Use of existing infrastructure, facilities, and elongation of useful life;

: Recoverable volumes, reservoir size, and complexity;

: Tariffs for processing the produced fluids on an existing installation;

: The potentially lower recovery rates from subsea tie-backs versus stand-alone development, due to limitations in the receiving facility’s processing systems;

: The potentially higher recovery rates from platform wells, due to easier access to well intervention and workover.

Limitations of long distance tie-back

  • Reservoir pressure must be sufficient to provide a high enough production rate over a long enough period to make the development commercially viable. Gas wells offer more opportunity for long tie-backs than oil wells. Hydraulic studies must be conducted to find the optimum line size.
  • It may be difficult to conserve the heat of the production fluids and they may be expected to approach ambient seabed temperatures. Flow assurance issues of hydrate, asphaltene, paraffin, and high viscosity must be addressed. Insulating the flowline and tree might not be enough. Other solutions can involve chemical treatment and heating.
  • The gel strength of the cold production fluids might be too great to be overcome by the natural pressure of the well after a prolonged shutdown. It may be necessary to make provisions to circulate out the well fluids in the pipeline upon shutdown, or to push them back down the well with a high-pressure pump on the production platform, using water or diesel fuel to displace the production fluids.

Stand-alone development

  • Figure 2-11 shows an example of a typical stand-alone oil field development for the Enfield field located off the North West cape in Western Australia at a 544-m (1,785 ft) water depth.
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