This paper presents case studies on reservoir and well management of two laterally and vertically compartmentalized Western Australian Triassic gas condensate reservoirs, developed by five multi-zone "smart" wells with sand control, tied back to an offshore platform via a subsea network. In managing assets with such complexity, it is imperative to understand reservoir performance on a zone-by-zone basis. Quantifying performance allows management of flux through downhole sand control systems and optimisation of offtake strategy. The majority of the material published to date on "smart" wells has been focused on completion design optimisation and minimisation of unwanted oil/water production. There are few existing articles about production and reservoir optimisation of high rate gas wells requiring flux management.
This paper showcases how remotely-operated selective completions ("smart" wells with permanent downhole gauges for each completion coupled with subsea flow meters for each well) have been instrumental in facilitating prompt analysis of zonal reservoir performance and thus in yielding insights into reservoir connectivity and allowing optimisation of zonal contributions. Various case studies will be presented showing how reservoir surveillance data is acquired and interpreted to optimize well zone-by-zone production and to manage flux limits on each producing zone. These case studies will include manipulation of downhole valves to provide information for established techniques such as interference testing and P/Z analysis.
Data acquisition and interpretation challenges are highlighted along with fit-for-purpose solutions developed to overcome those challenges.
The insights presented could facilitate better planning of similar systems in the future.
Australia is uniquely positioned globally as a major energy provider, but this comes with multiple challenges that must be overcome to realize its full potential. LNG developments that are nearing fruition are set to make Australia the largest supplier of LNG in the world. The Asian LNG market continues to be the growth market. The development of the world's first coal bed methane (coal seam gas) to LNG projects on the east coast has created a robust east coast LNG export market, which in the near future is expected to coincide with domestic energy shortages arising from low exploration activity, maturing fields, higher costs, the interaction of government policy, commercial decisions and activism. As a result, unique approaches to project management and community relations have been developed that are complementary to the Australian consumer's needs for reliable, affordable and cleaner energy. The east coast demand for gas is likely to trigger new development of onshore Northern Territory gas in the short term, if political opposition can be managed. In Western Australia, new approaches leverage technologies such as floating LNG, and more utilization of existing infrastructure and plant capacity to achieve lower costs. This paper outlines Australia's natural gas supply & demand and the challenges to be faced in the coming years.
On-bottom stability of subsea pipelines has been the focus of substantial research in recent years with particular emphasis on the topic of pipe-soil interaction. Numerous models have been developed to predict the pipe-soil interaction behavior under combined vertical and horizontal loading scenarios. The Verley and Sotberg energy based soil resistance model for silica sand is among these models. The model is recommended by Det Norske Veritas (DNV) and widely accepted and used by subsea pipeline design industry to model the pipe-soil interaction on silica sand soils. Calcareous sand soils are found in many of the world's offshore hydrocarbon development regions including offshore of Western Australia. The engineering characteristics of the calcareous sand are different from those of the typical silica sand soils. As such, Verley and Sotberg parameters for silica sand soils are not suitable for calcareous sand soils. This paper presents a calibration of the Verley and Sotberg silica sand soil resistance model for calcareous sand soil conditions using the results of a set of centrifuge tests of a pipe model on calcareous sand soil.
According to the European Wind Energy Association (EWEA) in the first six months of 2012, Europe installed and fully grid connected 132 offshore wind turbines, with a combined capacity totalling 523.2 MW. Overall, 13 wind farms were under construction. Once completed these wind farms will account for 3,762 MW. Europe is therefore the industry leader since the initiation of offshore wind turbine development. Most of the projects have been limited to less than 30-m deep waters in the North and Baltic Seas. However, planned offshore wind farms in Germany will be located in water depths up to 40 m. Future offshore sites in the UK include water depths to about 65 m. Offshore wind farm systems today use three types of foundation: monopile structures, gravity structures or multi-pile structures. They are economic in relatively shallow water depths. Current monopile diameters range between 4 and 6 m, wheres as piles for jacketed structures are smaller (i.e. between 2 and 3m). They are relatively easy to install, for instance, in soft clayey soils or sandy layers. There are, however, several situations where the pile driving installation is not suitable. The department of maritime technologies of BAUER Maschinen GmbH already developed other offshore foundation installation methods based on its know-how in the onshore foundation engineering practice.
According to the IREA report, offshore wind farms are at the beginning of their commercial deployment stage. Offshore turbines are designed to resist the more challenging wind regime offshore and require additional corrosion protection and other measures to resist the harsh marine environment. The increased capital costs are the result of higher installation costs for the foundations, towers and turbines, as well as the additional requirements to protect the installation from the offshore environment. The most obvious difference between onshore and offshore wind farms is the foundations required for offshore wind turbines. These are more complex structures, involving greater technical challenges, and must be designed to survive the harsh marine environment and the impact of large waves. All these factors and especially the additional costs of installation mean they cost significantly more than land-based systems. Besides, Moving offshore will allow the use of very large wind turbines capable of supplying typically 3.5 MW (although this will probably increase with time), installed in farms of 50 or more turbines. In contrast to typical oil and gas structures used offshore, for a wind turbine the foundation may account for up to 35% of the installed cost (Byrne and Houlsby 2003). These structures will be large; the turbine hub for a proposed 3.5 MW machine is expected to be some 90 m above the sea floor, with the rotor diameter likely to be of the order of 100 m. Initially the structures were installed in relatively shallow water (5-20 m in depth). While installing structures offshore is hardly novel, these structures are different from typical offshore structures (usually oil and gas structures) in two respects, both related to the applied loads on the structure and hence on the foundations (Byrne and Houlsby 2003). According to EWEA 270 foundations (141 or 109% more than the same period last year) were installed during the first six months of 2012 in 10 wind farms: Thornton Bank 2 (Belgium), Lincs, London Array, Sherigham Shoal, Gwynt y Môr, Teeside (UK), Anholt, Avedore 2 (Denmark), BARD Offshore 1 and Riffgat (Germany).Currently in Germany foundations depth ranges between 20 and 40 m, according to the BSH (Federal Maritime and Hydrographic Agency) at the current state. Turbine sizes range betwenn 3 and 5 MW.
Copyright 2012, Offshore Technology Conference This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 30 April-3 May 2012. This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material does not necessarily reflect any position of the Offshore Technology Conference, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of OTC copyright.