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 intent of this paper is to demonstrate the important role that the functionality and weight of a topsides has on the design and selection of a deepwater floating production platform. The discussion will focus on topsides of Tension Leg Platform, (TLP), Spar and Semisubmersible floating platforms in the deepwater Gulf of Mexico (GoM), but the principles apply to other deepwater regions as well. Early field development planning decisions that impact key topsides functions are addressed. These include whether or not to include a drilling or workover rig and choosing between developing the field with subsea (wet) or surface (dry) trees. Selecting a topsides installation method is a critical design consideration and must be firmed up early in the design cycle. Topsides installation options are presented as a function of topsides weight and platform type. The strong symbiosis between topsides weight and hull design is demonstrated. The need to prioritize topsides weight management is emphasized and some topsides weight reduction strategies are offered. Finally, topsides weight and water depth domains of applicability for various platform types are presented. These will allow development planning teams to rapidly converge on practical platform options during the screening process.
Reservoir Characteristics and Topsides Functions
When designing a floating platform topsides the first order of business is to establish its functional requirements (process, export, drilling, power, utilities, quarters etc.) and a design basis. These are primarily driven by the characteristics and fluid properties of the reservoir to be developed by the floating platform. Figure 1 is a schematic that shows how reservoir characteristics and its fluid properties influence decisions on topside functions.
The subsurface drilling and completions teams are responsible for specifying well count, top-hole locations, well production profiles, recovery mechanisms (natural drive, water injection, gas lift etc.) and fluid characteristics. These in turn determine the two most important topsides functional requirements: whether or not to have surface or subsea trees and whether to incorporate drilling or workover capability on the platform. These functional requirements fundamentally influence size and weight of topsides and platform selection.
Successful deepwater field development planning requires close collaboration between the subsurface, drilling and completions, surface facility, operation and business teams that jointly constitute the development planning team. The reservoir is the main driver of the development plan. Despite significant technological advances in reservoir characterization, there remains a high degree of uncertainty in predicting well performance and recovery. This is attributable largely to the very high cost of deepwater drilling exploration and appraisal of deep reservoirs which limits the data set of key parameters required to construct the reservoir and geologic models. The development planning team must quantify and manage this uncertainty to mitigate the potential for an over or under designed surface facility.
In this paper, important factors that drive the selection of a deepwater field development and floating platform are identified. Linkages between key reservoir and fluid characteristics and surface facility parameters are established. Strategies to manage reservoir and well performance uncertainty, particularly in deeper, subsalt reservoirs with few production analogs, are discussed.
The focus of this paper is on mature deepwater basins in the GoM, West Africa and Brazil. These are principally oil fields with associated gas and account for over 90% of total deepwater production. Regional drivers play an important role in field development planning and platform selection. A high level overview of deepwater platform selection in the GoM is presented.
Deepwater Field Development Selection Drivers
The process of selecting a field development plan following a discovery involves a complex iterative interaction of its key elements (subsurface, drilling and completions, surface facilities) subject to regional and site constraints (Figure 1). The objective is to select a development plan that satisfies an operators' commercial, risk and strategic requirements. The selection occurs while uncertainty in critical variables that determine commercial success (well performance, recoverable reserves) is high. The challenge 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. Selecting a floating production platform is a subset of the overall field development plan. A brief description of the more significant field development selection drivers follows.
Reservoir Geology and Geometry
Reservoir geology, geometry, fluid properties and flow rates of trapped hydrocarbons have the greatest impact on the field development plan. Table 1 summarizes relative impacts of key reservoir characteristics on primary field development parameters. Geologists and reservoir engineers create geological and reservoir models from seismic and well log data obtained from exploration and appraisal activities. Permeability and porosity of the reservoir rock are the principal determinants of well performance, (well rates and recovery) and well count. Generally, higher rock permeability and porosity yields better well performance, and fewer development wells.
Deep water developments are being pursued vigorously in various parts of the world (West Coast of Africa, Gulf of Mexico
etc.). The riser system is a critical part of the field architecture. Riser failure results in reduction or cessation of revenue. It may
also lead to spillage or pollution and could endanger lives. Hence, riser design must carry a high degree of reliability.
Steel Catenary Risers (SCRs) are considered to be technically feasible and commercially efficient solutions especially when
high temperatures and pressures are involved. However, in terms of fatigue, SCRs are very sensitive to environmental loading.
The procedure for fatigue analysis is essentially deterministic.
This paper concentrates on the probability of fatigue failure associated with the design of current practice of fatigue analysis of
SCRs. The procedure is illustrated with sample calculations with first order vessel motion and a flow chart for assessing the
probability of fatigue failure is also given. The example is chosen so as to highlight the issues involved. The probability of
failure is used to determine the ‘safety index'. The probability calculations have been reformulated so that they are applicable
for the design of SCRs. The probability of fatigue failure, associated with the recommended factor of safety in API RP 2RD,
for the example chosen, is also reported. The overall aim is to increase the confidence in the design of such systems in deep
A typical SCR attached to a Floating Production Storage & Offloading (FPSO) vessel and part of a deep water field
development is shown in Fig. 1. The riser is continuously subject to oscillatory environmental loads. The principal source of
structural loading is the ocean waves that impact the riser coupled with the complicated movements of the vessel which itself
comprise high frequency response to the waves and low frequency (slow drift) excursion. This paper is concerned with wave
induced fatigue only. Stresses resulting from environmental loading and corresponding structural dynamic response at a joint
(node) are typically random in nature, as shown in Fig. 2. Metal fatigue in the weld at the joint, due to these oscillatory
stresses, is one of the likely causes of failure.
Most vulnerable to fatigue are the welded joints near the touch down point (see Fig. 1) because of high cyclic bending stresses
and stress concentration due to both joint geometry and weld defects.
Fatigue life prediction in SCRs is a complicated process involving many factors and has been discussed at length by Campbell
(1999). Current practice, mainly deterministic in nature is summarised first.
LNG is a proven gas monetization option that has grown over the past 30 years from a 3 MMTPA industry in the early 1970s to 106 MMTPA industry in 2001. Even so, LNG today accounts for only about 6% of the total natural gas consumed worldwide. The growth in LNG is forecast to remain strong in the coming decade. The ability of the LNG option to continue to compete with existing and emerging gas monetization options will depend on the industry's success in reducing cost throughout the LNG value chain and maintaining exceptional safety, reliability, and environmental performance.
This paper reviews the different components of the LNG value chain from the gas field to the eventual consumer with emphasis on liquefaction plant and regasification terminal. The paper addresses feed gas treatment, liquefaction process technologies, utilities and typical CAPEX for the LNG liquefaction facility. For regasification terminals, the paper will describe off-loading systems, storage tanks, regasification process, vaporizer designs, safety issues and typical CAPEX.
The engineering of LNG liquefaction and regasification facilities is considered a mature technology. However, there are several developments that have or will lead to reduction in life cycle cost of these facilities making LNG a more competitive gas monetization option. These developments include large capacity LNG plants, use of large single shaft gas turbine drivers, all electric drives, and offshore LNG facilities.