Producing and delivering North West Australia (NWA) deepwater gas reserves to LNG plants poses unique challenges. These include extreme metocean conditions, unique geotechnical conditions, long distances to infrastructure and high reliability/availability requirement of supply for LNG plants. A wet or dry tree local floating host platform will be required in most cases. Whereas semisubmersible, TLP, Spar and floating LNG (FLNG) platform designs all have the attributes to be a host facility, none has been installed in this region to date.
This paper will address important technical, commercial and regulatory factors that drive the selection of a suitable floating host platform to develop these deepwater gas fields off NWA. Linkages between key reservoir and fluid characteristics and surface facility requirements will be established. A focus will be on the unique influence of regional drivers and site characteristics including metocean and geotechnical conditions, water depths and remoteness of these fields.
There have been 17 FPSOs producing oil in Australian waters. These facilities have been chosen because of the remoteness of the fields and the lack of pipeline and process infrastructure. Storing oil on the FPSO for offloading and shipping from the fields becomes an obvious solution. Semisubmersible, TLP or Spar platforms show little advantage in such developments.
For deepwater gas developments, the product has to be processed, compressed and piped to shore for liquefaction. As host processing facilities, Semisubmersible, TLP and Spar platforms have clear advantages over FPSOs because of their superior motion performance in the harsh Australian metocean environment and other benefits such as facilitating drilling, dry tree completion and well services. FPSOs or FSOs may be applied for storage of associated oil and condensates. For marginal and remote gas field developments, an LNG FPSO (FLNG) may be an attractive option as it eliminates long pipelines and land-based liquefaction plants.
As discussed by Dorgant and Stingl (2005), a deepwater field development life cycle following discovery usually involves five distinct phases, Figure 1. The "select?? phase occurs after a discovery has been appraised sufficiently to further evaluate it for development. It consists of evaluating multiple development concepts and scenarios and selecting the one that will most likely achieve the identified commercial and strategic goals. Selecting a floating platform and its functions for a deepwater development is an important subset of the select phase and the overall field development planning.
The process of field development planning involves a complex iterative interaction of its key elements (subsurface, drilling and completions, surface facilities) subject to regional and site constraints (D'Souza, 2009). The objective is to select a development plan that satisfies an operator's commercial, risk and strategic requirements. It entails developing a robust and integrated reservoir depletion plan with compatible facility options. The selection occurs while uncertainty in critical variables that determine commercial success (well performance, reserves) is high. One of the challenges is to select a development plan that manages downside reservoir risk (considering the very large capital expense involved) while having the flexibility to capture its upside potential.
The objective of the work is to assess the feasibility of a tension legplatform (TLP) dry tree unit (DTU) with tender-assisted drilling (TAD) for theharsh metocean conditions offshore North West Australia, characterized by theoccurrence of tropical cyclones and persistent swells. Making use of thedrilling tender vessel's accommodation, power generation, mud pumping, cleaningand storage facilities etc. can reduce the production platform topsides weightby up to 3,000 tonnes. Such weight and associated cost savings could becomeenablers for some of the deepwater gas field developments offshore WesternAustralia.
A TLP configuration is evaluated as the DTU in a water depth of 500 m. The TLPis sized for a specific payload for gas production. A typical 6-columnsemisubmersible is configured as the drilling tender vessel (DTV), for which apreliminary TAD mooring system is defined. Hydrodynamic models for the combinedDTU/DTV systems are developed and used to perform extreme response andoperability analyses.
The coupled TLP/DTV TAD system is analyzed in 1, 10 and 100-year return periodenvironments. It is shown that the DTU and DTV vessel can be safely mooredtogether by hawsers without collision in up to 10-year return cyclonic stormevents. This means that the mooring system operability of up to 99.97% isachievable.
In environmental conditions harsher than 10-year return cyclonic storms, theDTV will be disconnected from the DTU and a full 8-point mooring pattern willbe required to moor the DTV to survive up to 100-year return periodcyclones.