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.
The oil & gas industry is constantly adapting to change, be it related to price, technology or market demand. High prices of crude oil and advances in technology have allowed producers to access resources previously out of reach, and extract maximum value from these resources. With this, however, operational risk is significantly augmented - both upstream and downstream. In order to cope with this increased risk, it is vital that oil & gas companies have a process safety management (PSM) system that fully integrates management of change methodologies.
DuPont has developed a PSM system that fully integrates change management across multiple facilities, among personnel and in light of technological advancement. While these must be considered singularly, it is also important for companies to build a holistic system that accounts for the interdependent nature of operational systems, and thus address process safety from every possible angle - training and skill development to hazard analysis and maintenance. However, as only a limited number of procedures [PW1] can be universally applied to cope with changing process conditions, this paper will also detail the means through which companies can develop customized solutions for specific conditions and contexts.
By developing a model that can effectively manage change, it is possible for oil & gas companies to not only avoid catastrophic incidents, but also increase the overall safety of an operation, while concurrently maximizing efficiency, cost-effectiveness and quality.
The extraction and processing of oil and gas is a highly technical mechanical operation that involves volatile and corrosive substances in often extreme conditions. As such, it is vital for companies within the oil & gas sector to develop a holistic PSM system that can successfully manage process safety, while remaining agile enough to respond to specific issues, and any changes thereof.
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 paper will consider the implementation of the
safety case in the oil and gas industry internationally post -Macondo and Montara.
The National Commission Report into the Deepwater Horizon / Macondo blowout stated:
"The immediate causes of the Macondo well blowout … …. that reveal such systematic failures in risk management that they place in doubt the safety culture of the entire industry. "
In their letter to Minister Ferguson on 22 March 2011, the NOPSA Board stated:
"The Montara and Macondo incidents each demonstrate technical ignorance and a poor safety culture including complacency regarding low probability, high consequence risks. There is a clear need to improve industry safety culture, accountability and leadership."
The paper will examine these criticisms and consider how the industry
needs to improve its process safety and risk management. The implementation of a safety case in the USA may only occur "in the typical rule-making process that takes up to two years" (Michael Bromwich, Director of BOEMRE). Knowledge, understanding and application of key aspects of process safety management and the safety case process are not uniform. The paper will suggest how, in this context, the safety case can be applied to achieve the required outcomes.
The paper will draw from specific findings from the Macondo and Montara incidents.
There are echoes of Piper Alpha in the performance of emergency systems on Deepwater Horizon. The inadequate application of hazardous area classification is a key issue which the paper will examine in order to provide greater understanding. Whilst in Australia, issues of consistency and quality arise with matters such as performance standards. The paper will discuss the need for a standard for "performance standards" that goes beyond current regulatory guidelines.
Overall, the paper will seek to propose a way forward for the industry in several practical areas.
Technology is now available for real-time Industrial Hygiene monitoring of activities in locations such as offshore facilities, with viewing of the data remotely. The use of this technology can result in a more dynamic approach to hazard control, where the data being collected can be interpreted and control barriers altered in line with the results of monitoring. The data review can take place onshore by Industrial Hygiene specialists without the need to fly offshore. Encrypted data is transmitted via the internet for viewing onshore. No work on this application of real-time monitoring has been published previously. This innovative technology is being trailed by Shell in Australia in what is believed to be a world first.
Real-time personal monitoring equipment is available for monitoring of compounds such as VOC (Volatile Organic Compounds), benzene, heat stress, radiation and dust. The application of this type of monitoring is extremely useful in a dynamic environment such as offshore exploration drilling or during commissioning of new offshore facilities. In these environments there is limited opportunity for specialist resources such as Industrial Hygienists to be present offshore as operationally, manning levels are at their maximum during these periods.
The use of real-time monitoring with remote review by Industrial Hygiene specialist makes it possible to monitor unique, uncommon, or unplanned maintenance tasks that would otherwise be very difficult to capture.
This paper will provide results and conclusions from the trial of this technology during the refit of an LNG Tanker in Singapore and will describe how this technology may be implemented in remote facilities such as Shell's Prelude FLNG facility. The paper will also discuss likely advances in this technology over the next few years.
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.