EQUIPMENT/ENGINEERING: Prudent use of riser technology drives deepwater development cost efficiency

Selecting appropriate oil and gas infrastructure scenarios is a major challenge for any deepwater field development. At present, it is not uncommon for develop-ment scenarios to be built up around the types of surface facilities that are deemed to be appropriate for the particular field. For example (in deepwater), moored spar systems, tension leg platforms (TLPs), semisubmersible systems, barges, mini-TLPs, or subsea christmas trees tied back to a host platform may be considered to be appropriate.

On the face of it, this may seem to be a reasonable means of developing the options, particularly as the surface facilities may well comprise a significant component of development capital expenditures.

Such an approach, while appearing to be reasonable, does not robustly address an important area of field development scenario evaluation. The cost of the risers themselves may not dominate the final development cost, but the effect that these risers will have on the total cost may well be more significant than is generally appreciated, according to Kevin Burton, Director of Riser Systems with the UWG Group.

For example, he points out, in a field where a relatively large number of deepwater wells are required, and a dry tree system has been selected, the consequences for the surface facilities may be significant. If a Spar has been selected, there will need to be a substantial wellbay area, large enough to accommodate all the risers, and with sufficient room to allow the risers to stroke up and down.

If a TLP has been selected, Burton says, it will also need a large wellbay area, and must be capable of supporting the necessary top tensioned risers. In such cases, the cost of the development option will be heavily influenced by the surface facility size (and hence cost), of which a large proportion is likely to be related to the riser systems that are being utilized.

If a subsea development scenario is envisaged in either of the above cases, drilling and workover costs are likely to be substantial, driven primarily by expensive vessel day rates and/or long, complex deviated wells. In these cases, the cost of flow lines and risers will, again, be significant depending upon issues such as flow assurance and the distances back to the host platform.

By ensuring the riser system options are fully evaluated during the early stages of working up field development scenarios, a major financial prize can be gained, Burton points out. This can be manifested not only in reduced riser costs, but also reduced surface facility costs, and in some cases also reduced drilling costs. The latter two cost savings are likely to far outweigh any savings in the risers themselves, but they can only be achieved by an integrated approach that is built up around an effective riser evaluation, early in the project.

2H Offshore Engineering, a subsidiary of the UWG Group, has pioneered development of riser solutions, one of which is known as STORMTM). Burton contends the system enables fields to be drilled and produced using a lower cost platform or vessel by making use of a combination of existing proven products. The program is claimed to provide advantages associated with dry trees and subsea developments, without the disadvantages of either.

The system uses horizontal trees located on modular manifolds below a floating vessel. This can be a barge, semisubmersible, or spar. The wells are drilled in the same manner as a dry tree system, using a surface BOP and completed with a subsea tree. The arrangement provides efficient drilling and vertical access for workover operations.

Each manifold supports up to five wellheads and is connected by a short spool to the base of a single line offset riser (SLORTM) or concentric offset riser (CORTM). These provide a non-motion sensitive flow path to the production vessel, enabling the use of a cost-effective barge or semisubmersible vessel, Burton stated.