The Ichthys LNG Project
INPEX has begun construction of one of the world's largest oil and gas projects following the Final Investment Decision (FID) on the US $34 Billion Ichthys LNG Project in Australia on 13 January 2012. The Ichthys LNG Project is a joint venture between INPEX (Operator) and Total with Tokyo Gas, Osaka Gas, Chubu Electric and Toho Gas.
The Ichthys Field is situated in the Timor Sea approximately 200 kilometers off the Western Australian coast and over 800 kilometers from Darwin. Three exploratory wells drilled in 2000 and 2001 resulted in the discovery of an extremely promising gas and condensate field with resource estimates from two reservoirs totaling approximately 12TCF of gas and 500 million barrels of condensate. Conceptual studies, FEED and ITT followed and development leading to sanctioning of the Ichthys LNG Project by INPEX and Total.
Gas from the Ichthys Gas-Condensate Field in the Browse Basin will undergo preliminary processing offshore to remove water and extract condensate. The gas will then be exported to onshore processing facilities in Darwin via an 889 kilometer subsea Gas Export Pipeline (GEP). Most condensate will be sent to a Floating Production Storage and Offloading (FPSO) vessel for stabilization and storage prior to being shipped to global markets. The Ichthys LNG Project is expected to produce 8.4 million tons of LNG and 1.6 million tons of LPG per annum, along with approximately 100,000 barrels of condensate per day at peak.
Production from 20 subsea wells in the first phase - 50 will be drilled in total - will be sent to the Central Processing Facility via 8?? rigid lines connected to flexible risers. The flexibles will be supported by a 110 meter high jacket type riser support structure. You see, no aspect of the Ichthys LNG Project is small.
Effluents will be separated on the Central Processing Facility (CPF), a semi-submersible floater. Gas will be dried and compressed prior to being sent ashore via a GEP. Compression will be from four compressors, designed for 590.7 MMSCFD. Following initial treatment, most liquids will be transferred from the CPF to the nearby FPSO for processing and storage. The 330 meter-long FPSO will be a weather-vaning ship-shaped vessel that is permanently moored on a non-disconnectable turret. It has been designed with a storage capacity of nearly 1.2 million barrels. Loading of two offtake tankers in tandem will be possible from the FPSO.
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.
Liu, Zhen (Jiangsu University of Science and Technology) | Zhu, Renqing (Jiangsu University of Science and Technology) | Ji, Chunyan (Jiangsu University of Science and Technology) | Chen, Minglu (Jiangsu University of Science and Technology) | Teng, Bin (Dalian University of Technology) | Li, Liangbi (Jiangsu Modern Shipbuilding Technology Co. Ltd, Jiangsu University of Science and Technology)
Demand for natural gas is increasing more rapidly than anticipated in Far East markets because (1) China has modified its policies in order to increase reliance on gas, in part to mitigate the growth in its coal consumption (which now stand at almost half of world coal production), (2) Japan has announced its intention to eventually shutdown its nuclear power industry, and (3) India, which currently has more than 400 million people without electricity, desires to accelerate electrification. This analysis investigates the potential role of stranded gas from Central Asia, Russia, Southeast Asia, and Australia in meeting Asia's future demand for gas imports. It initially surveys the discovered or known gas in stranded gas accumulations in Central Asia, Russia, Australia, Indonesia, and Malaysia. It then examines the primary gas import markets of China, India, Japan, and South Korea by describing energy use, gas demand trends, and domestic gas supplies to establish boundaries that encompass the wide variation in gas import demands in these markets during the two decades following 2020.
Then the cost of developing and delivering gas through overland pipelines from selected stranded gas fields in Central Asia and Russia to China is examined. Analysis shows that for the Shanghai market in China, the costs of developing and delivering Russia's stranded gas from the petroleum provinces of eastern Siberia are competitive with costs estimated for stranded gas from Central Asia. However, for the Western Siberian Basin, delivered gas costs are at least 3 US dollars per thousand cubic feet (USD/Mcf) higher than delivered gas from Central Asia.
The extraction and transport costs to a liquefaction plant for gas from stranded gas fields located in Australia, Indonesia, Malaysia, and the basins of eastern Siberia are then evaluated. The resource cost functions presented show development and extraction costs as a function of the volume of stranded gas developed for each country. The analysis demonstrates that, although the Russian fields in areas of eastern Siberia are large with relatively low extraction costs, distances to a potential liquefaction plant at Vladivostok make them initially the high cost suppliers of the liquefied natural gas (LNG) market. For the LNG markets examined, Australia and Malaysia are initially the lowest cost suppliers. For the Shanghai market, a comparison of the cost of supplying gas by pipeline with the cost of supplying LNG shows that the pipeline costs from areas of eastern Siberia and Central Asia are generally lower than delivered cost of gas as LNG from the LNG supply sources considered.
In a world where perception is reality it is crucial for oil & gas companies to maintain transparent and constructive relationships with their stakeholders. To ensure business continuity companies must build strategies that are centered on respect, listening, dialogue and stakeholder involvement. This has come to be known as establishing a "social license to operate.??
With this in mind, and with the help of the Altermondo consultancy, Total developed the SRM+ tool in 2006. This is a methodology by which an entity (a project group, a subsidiary) compares its internal vision of the societal context in which it operates with the perception of its external stakeholders and builds action plans aimed at bridging the gaps between them.
In 2011 the Ichthys LNG Project in Australia, a Joint Venture between INPEX (operator) and Total, applied the SRM+ tool. A total of 35 external stakeholder groups were interviewed, from the Northern Territory, Western Australia and the Australian Capital Territory.
Although most stakeholders stated they were very satisfied with the quality of their relationship with INPEX and the Ichthys Project, several valuable suggestions were made on how to improve the dialogue and strengthen relationships. The SRM+ process provided valuable insights that are difficult to glean from routine interaction with stakeholders. It also gave confidence to the Project managers that they understand the issues, concerns and expectations of key stakeholders and that external risks are being appropriately managed.
Following the SRM+ engagement, several Project managers made adjustments to their strategies. Possibly the most important outcome of SRM+ was that it has created the foundation for the Ichthys Project's long-term approach to stakeholder engagement. Going forward, INPEX plans to build on the SRM+ process by developing and deploying a stakeholder relationship management software package for the Ichthys Project that will enable the organization to identify, manage and respond to issues of importance to its stakeholders. Doing so will ensure that the Ichthys Project is able to maintain its social license to operate.
Oil & Gas companies dedicate considerable budgets to CSR programs. It is essential that these are developed taking the views and concerns of stakeholders into consideration to guarantee their effectiveness and sustainability. Therefore, engaging with stakeholders is vital to success and companies must provide their stakeholders with both the opportunity and the means to present their views and voice their concerns.
This paper addresses through the practical example of the implementation of SRM+ on the Ichthys LNG Project, some of the key questions companies face when defining and implementing a CSR strategy.
The SRM+ approach is based on the assumption that soliciting stakeholders' views of, and concerns about, a company's activities is best achieved through open, guided discussions. One way interviews can be restrictive.
The bulk of Chevron Australia's field operations are carried out in hot areas of Western Australia (WA). The climate, the work environment and the nature of tasks being carried out mean that heat stress management is a critical element in the Company's health protection efforts. Heat illness produces outcomes that vary from mild levels of fatigue and discomfort through to life threatening conditions such as heat stroke. Additionally, it is well recognised that excessive deep body temperature and dehydration are connected with a decrement in both physical and mental performance, and hot conditions may thereby give rise to accidents and significant productivity loss.
Many of the logistical, earthworks and construction tasks now underway in advance of the Gorgon Project's operational phase are carried out in the open, with an accompanying high risk of UV exposure. As such, skin cancer protection is an important additional consideration.
What sets this work apart from the work of others is:
? The project was applied in a challenging, construction work environment characterised by constant change and many newcomers
? There was a focus on connecting well established scientific understanding with day-to-day practice in the field
? The project centred on an integrated approach to dealing with the twin issues of heat stress and UV protection
? Several new training packages, checklists, surveys and field trials were introduced
? There was a close connection with external stakeholders, including the Cancer Council Western Australia (CCWA), WorkSafe WA and the Commission for Occupational Safety and Health
The project involved the development and communication of expectations, procedures and processes to support leading practice management of heat stress and UV exposure.
The paper describes a comprehensive approach to both heat management and sun protection. It should have broad applicability to Oil and Gas Industry operations in warmer parts of the world.
In Western Australia, Chevron leads the development of the Gorgon and Wheatstone natural gas projects, two of Australia's largest-ever resource projects. In addition, the Company manages an equal one-sixth interest in the North West Shelf Venture, is a participant in the proposed Browse LNG Development and operates Australia's largest onshore oilfield on the Barrow Island and Thevenard Island oilfields. It is expected that first gas for the Gorgon Project will be in 2014, while that for Wheatstone will be in 2016. The construction workforce for each project will peak at approximately 5,000 workers.
This paper presents a methodology for a systematic, robust and conservative ecological risk assessment for estimating environmental consequences and associated risk from ambient air concentrations of atmospheric pollutants and air toxics (also referred to as criteria pollutants and hazardous atmospheric pollutants in the United States legislation respectively), as arising from industrial activities. The paper details the main steps of the risk assessment process and makes a contribution in deriving conservative and safe Reference Concentrations (RfC) such as No Observed Adverse Effect Level (NOAEL) and Lowest Observed Adverse Effect Level (LOAEL) for fauna in their natural habitat, using published scientific dose-response toxicological studies with laboratory animals. It then uses these derived RfCs to determine step changes in consequence levels, from incidental to major, in order to complete the risk assessment. A similar approach is used to assess impacts on the marine environment. This methodology is repeatable and robust and can be applied as a screening level environmental risk assessment to establish conformance to legally postulated levels of acceptable environmental consequences, where available, or acceptable levels of environmental risk, associated with air quality.
Project Background and Setting
The Gorgon Project, operated by Chevron Australia Pty Ltd on behalf of the Gorgon Joint Venture Participants, will develop the Gorgon and Jansz-Io gas-condensate fields, located offshore the north-west corner of Western Australia (WA) (see Figure 1). The approved development will include subsea gathering systems and pipelines delivering the gas to a 15 million tonne per annum (MTPA) liquefied natural gas (LNG) Gas Treatment Plant (GTP) located on the east coast of Barrow Island (BWI), which is a Class A nature reserve, lying some 60 km north of the Australian mainland. The Gorgon Project is an unique LNG Project in that it will also encompass the largest industrial scale acid gas injection undertaking in the world to date whereby some 4.2 MTPA of CO2 and other acid gas components (i.e. residual methane, (CH4), volatile organic compounds (VOCs) and hydrogen sulphide (H2S) removed from the natural gas, will be liquefied and injected via three injection centres in the Dupuy Formation below BWI in the Operations Phase of the Project.
In May 2011 Shell announced its commitment to the development of a Floating Liquefied Natural Gas (FLNG) concept by taking the Financial Investment Decision on the Prelude FLNG Project. Prelude is located in Australian offshore waters, approximately 475 km north-northeast of Broome and 825 km west of Darwin, and will be Shell's and possibly the world's first FLNG development. FLNG offers a number of environmental advantages over traditional onshore LNG developments. This paper describes some of these and the associated environmental permitting/approval conditions for the project.
This paper describes a novel instrumental technique using astronomical cameras modified to monitor the whole-of-sky light emissions visible to marine turtles nesting near industrial developments in Western Australia. The results provide quantitative and qualitative data on specific light sources including sky glow which cannot be otherwise be measured in a field setting. The quantitative and qualitative results provide environmental practitioners and managers with the first reliable tool with which to monitor light emissions. This instrumental method has application well beyond marine turtles and can be used to measure and monitor light in any setting and for any receptor (wildlife or human) exposed to light, either astral or artificial.