Abstract
Abstract Many of the world’s largest and most profitable offshore oil and gas basins are reaching maturity and are declining in profitability. Most new discoveries tend to be smaller and present as fragmented and geographically dispersed reservoirs with substantial uncertainty concerning geology and marginal exploration costs. Many of these discoveries only make sense when considered as a set. This situation is compounded by large oil and gas price volatility and a very large combinatorial size of the design and operational decision space. Subsea tiebacks that connect new fields to existing production facilities are a means of extending the life and profitability of offshore facilities. The challenges of subsea tiebacks are both technical – they require connecting fields and facilities over large distances (>10 km) in deep water (>500 m) – and conceptual. It is not immediately clear where we should place production facilities, how we should size them, and in what sequence and when we should place tiebacks to optimize value. This article presents a methodology that evaluates three kinds of flexibility as a means to mitigate uncertainty in subsea tiebacks: the ability to tie back new fields, the ability to expand the capacity of a central processing facility, and the dynamic allocation of processing capacity to the connected fields. The methodology uses an integrated mid-fidelity system model in conjunction with Monte Carlo simulation to identify potential platform design capacities and tieback phasing strategies under reservoir, facilities, and market uncertainties. We demonstrate the methodology on an offshore multiple-oilfield development patterned after a real case off the West Coast of Africa. The results show that because of the concurrent presence of reservoir, facilities, and market uncertainties, implementing flexibility significantly increases, by as much as 76%, the expected net present value of the project compared to a traditional point-optimal inflexible design.
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